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Please visit our website for all tickets sales and event/course registrations Office hours: Monday to Friday, 8:00am to 4:30pm
The CSPG Office is Closed the 1st and 3rd Friday of every month.
OFFICE CONTACTS
Membership Inquiries
Tel: 403-264-5610
Email: membership@cspg.org
Technical/Educational Events: Biljana Popovic
Tel: 403-513-1225 Email: biljana.popovic@cspg.org
Advertising Inquiries: Emma MacPherson
Tel: 403-513-1230 Email: emma.macpherson@cspg.org
Sponsorship Opportunities: Candace Seepersad
Tel: 403-513-1227 Email: candace.seepersad@cspg.org
Conference Inquiries: Candace Seepersad
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CSPG Educational Trust Fund: Kasandra Amaro
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Accounting Inquiries: Eric Tang
Tel: 403-513-1232 Email: eric.tang@cspg.org
Executive Director: Lis Bjeld
Tel: 403-513-1235, Email: lis.bjeld@cspg.org
EDITORS/AUTHORS
Please submit RESERVOIR articles to the CSPG office. Submission deadline is the 23rd day of the month, two months prior to issue date. (e.g., January 23 for the March issue).
To publish an article, the CSPG requires digital copies of the document. Text should be in Microsoft Word format and illustrations should be in TIFF format at 300 dpi., at final size.
CSPG COORDINATING EDITOR
Emma MacPherson, Communications Coordinator, Canadian Society of Petroleum Geologists Tel: 403-513-1230, emma.macpherson@cspg.org
The RESERVOIR is published 11 times per year by the Canadian Society of Petroleum Geologists. This includes a combined issue for the months of July and August. The purpose of the RESERVOIR is to publicize the Society’s many activities and to promote the geosciences. We look for both technical and non-technical material to publish. The contents of this publication may not be reproduced either in part or in full without the consent of the publisher. Additional copies of the RESERVOIR are available at the CSPG office.
No official endorsement or sponsorship by the CSPG is implied for any advertisement, insert, or article that appears in the Reservoir unless otherwise noted. All submitted materials are reviewed by the editor. We reserve the right to edit all submissions, including letters to the Editor. Submissions must include your name, address, and membership number (if applicable).The material contained in this publication is intended for informational use only.
While reasonable care has been taken, authors and the CSPG make no guarantees that any of the equations, schematics, or devices discussed will perform as expected or that they will give the desired results. Some information contained herein may be inaccurate or may vary from standard measurements. The CSPG expressly disclaims any and all liability for the acts, omissions, or conduct of any third-party user of information contained in this publication. Under no circumstances shall the CSPG and its officers, directors, employees, and agents be liable for any injury, loss, damage, or expense arising in any manner whatsoever from the acts, omissions, or conduct of any third-party user.
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Mount Victoria, Banff National Park, Alberta. Looking west to an icefall cascading over the grey and brown limestones and dolomites of the Middle Cambrian Cathedral Formation on Mount Victoria in Banff National Park, Alberta.
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PRESIDENT
Tony Cadrin • Journey Energy Inc. president@cspg.org@cspg.org Tel: 403.303.3493
PRESIDENT ELECT
Greg Lynch • Shell Canada Ltd presidentelect@cspg.org Tel: 403.384.7704
PAST PRESIDENT Dale Leckie pastpresident@cspg.org
FINANCE DIRECTOR
Astrid Arts • Cenovus Energy directorfinance@cspg.org Tel: 403.766.5862
FINANCE DIRECTOR ELECT
Astrid Arts • Cenovus Energy directorfinanceelect@cspg.org Tel: 403.716.3205
DIRECTOR
Mark Caplan • Athabasca Oil Sands Corp. mcaplan@atha.com Tel: 403.975.7701
DIRECTOR
Milovan Fustic • Statoil Canada Ltd. publications@cspg.org Tel: 403.724.3307
DIRECTOR
Michael LaBerge • Channel Energy Inc. memberservices@cspg.org Tel: 403.301.3739
DIRECTOR
Ryan Lemiski • Nexen Energy ULC youngprofessionals@cspg.org Tel: 403.699.4413
DIRECTOR
Robert Mummery • Almandine Resources Inc. affiliates@cspg.org Tel: 403.651.4917
DIRECTOR
Darren Roblin • Kelt Exploration corprelations@cspg.org Tel: 587.233.0784
DIRECTOR
Jen Russel-Houston • Osum Oil Sands Corp. Jrussel-houston@osumcorp.com Tel: 403.270.4768
DIRECTOR
Eric Street • Jupiter Resources street@jupiterresources.com Tel: 587.747.2631
EXECUTIVE DIRECTOR
Lis Bjeld • CSPG lis.bjeld@cspg.org Tel: 403.513.1235
A message from Milovan Fustic
A synopsis of my tenure as a board member of CSPG in only two words - THANK YOU!
There are many people who did hard and excellent work that I am very pleased to summarize and report on.
After several years of evaluation our Bulletin of Canadian Petroleum Geology (BCPG) is only one issue away from being eligible to apply for re-instatement with the ThomsonReuters journal ranking service! This is fantastic news for everyone who enjoys publishing and will certainly attract more highquality scientific papers from both industry and academia. Behind this success are BCPG editors, Dave Morrow and Burns Cheadle, along with associate editors who together ensured timely production of the Bulletin while maintaining rigorous review processes ensuring the acceptance of appropriately high-quality scientific papers.
In addition to the recently published thematic issue about geology and petroleum systems of Baffin Bay by James Haggart, the Bulletin has lined up a series of thematic issues which include:
i. “Devonian Beneath Oil Sands” with Dr. Chris Schneider (University of Alberta) and Darrell Cotterill (Parallax Resources) as guest editors;
ii. “Advances in Applied Geomodeling” a compilation of invited papers from proceedings at the Gussow 2014 Conference “Closing the Gap 2” with David Garner, Olena Babak and Clayton Deutsch as guest editors;
iii. “Biogenic Gas fields in Canada and China: Characterizations and new insights” with Dr. Zhuoheng Chen and Steve Grasby as guest editors;
iv. Importance of Rock Properties in Unconventional Reservoirs” with Ken Potma, Chad Glemser and Ryan Mohr acting as guest editors, and
v. Oil sands and Heavy Oil: A local to global multidisciplinary collaboration” with Fran Hein, Chris Seibel, Dale Leckie and Kevin Parks as guest editors.
If you have material that you would like to publish in any thematic issues please consider being invited and contact guest-editors directly to propose a paper! Also, if you have a topic in mind that you like to know more about, please contact us and propose thematic issue. The Bulletin continues publication of regular issues on topics of interest to the petroleum industry.
A compilation of the very popular “Go Take a Hike” articles from our Reservoir Magazine are in the process of being published into a book., I am sure this will be the ‘must have item’ in every geologists library and hiking back-pack. Kudos to Phil Benham and his team on their dedication to create both the series of articles in the Reservoir and the book!
This time last year I wrote the comment “Let’s publish” with CSPG in which I have reviewed the reasons for publishing in the BCPG, some of which I would like to repeat in somewhat shorten version:
• This is good for your employer: through your publication, your organization does not only demonstrate their technical competency and resources, but frequently this is the most elegant way for protecting IP (intellectual property) rights. Technical publication commonly allows a company to evaluate potential patenting resulting from the work for a period of time following publication and ensures their freedom to operate.
• Because this is good for you: from peerreview comments and citations to your work in a follow up publications you and your co-authors will expand knowledge on the topic; your article becomes accessible through various worldwide (... Continued on page 7)
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» Optimized horizontal drilling through petrophysical or geomechanical models
» Integrated earth modeling to accommodate all supporting field development data including seismic data, microseismic data, engineering data, well log data, and core data with animations of all time-dependent data
» Discrete fracture network modeling, fracture probability modeling, facies modeling, chronostratigraphic modeling, and a unique stimulation fracture path modeling solution to better model hydraulic flow as a function of time
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DIAMOND
AGAT Laboratories
The CSPG Educational Trust Fund
Cenovus Energy
Tourmaline Oil Corp.
ConocoPhillips Canada Limited
Nexen ULC
Imperial Oil Resources
Schlumberger Canada Limited
IHS Global Canada Limited Baker Hughes
Suncor Energy
Devon Energy Corp
Seitel Canada Ltd.
Enerplus
Husky Energy Inc. SILVER
Canadian Natural Resources Ltd
Chinook Consulting
CSEG
Arcis Seismic Solutions
MJ Systems
Cabra Consulting Inc.
Emerson Process Management
EOG Resources Canada Inc. BRONZE
Canada Partnership
Osum Oil Sands Corp. Pro Geo Consultants
Qatar Shell GTL Limited
AAPG - Canada region
Ikon Science Ltd.
Pengrowth Corporation
Crescent Point Energy Trust Geovariances Paradigm
Pason System
Geomodeling Technology Corp.
Painted Pony Petroleum Ltd.
Canadian Discovery Ltd.
RPS Energy Canada Ltd.
Encana Corporation
GLJ Petroleum Consultants Ltd.
Sproule Associates Limited
Streamsim Technologies, Inc.
Tucker Energy Services Canada
(... Continued from page 5)
geoscience search engines; you qualify for APEGA’s PDH credits; your diagrams will never fade; your publication is a nice addition to your CV and technical portfolio; publishing is the best recipe for protecting your work and ensuring its legacy as a contribution to geoscience.
• Because we owe it to people we learned from: Canada is place where many geoscience concepts were developed and ideas tested. The latter happened because of people like you, people who had ideas and courage to share it with others and made time to publish it. Can you imagine where our industry would be today if W. C. Gussow in his 1954 paper on “differential entrapment of oil and gas” had not paved the way for petroleum system analysis nowadays routinely applied worldwide? How many more dry holes would have been drilled? Simple and obvious today, his concept was controversial and contrary to accepted ideas at the time when he published. But, he had an important idea and the perseverance to publish it.
One thing I did not know at that time was that your publication with BCPG is also creating a monetary value. In fact, just last year CSPG received revenue from downloaded papers that exceeded 40K! This revenue supports CSPG’s activities including best student MSc and PhD thesis and student industry field trips.
I would like also to welcome Jen RussellHouston, who recently joined the board
and has already sparked a number of ideas about how to promote and help publications. As a result of her initiative CSPG will soon offer free of charge sessions / workshops about how to publish scientific papers in the Bulletin (BCPG)! If you are looking for some guidelines and help, you will receive it first hand from BCPG editors.
Lis Bjeld (CSPG manager) and Emma MacPherson (CSPG office staff member) are thanked for keeping things in order and for all their hard work on promoting publications behind the scene.
Finally, I would like to thank all of the people who decided to take the time contribute scientific and/or technical literature through the past year and all who are working on publications right now.
And for the rest of you – I sincerely look forward to seeing your names in published literature soon!
I welcome any comments, thoughts or ideas you may have. I also welcome your suggestions for Memoirs and Special Publications and BCPG’s thematic issues. Feel free to contact me at mfus@statoil.com
SPEAKER
Cathy Busby University of California
11:30 am
Tuesday, April 7th, 2015 Calgary, TELUS Convention Centre Macleod Hall C/D Calgary, Alberta
Please note: The cut-off date for ticket sales is1:00 pm, three business days before event. [Thursday, April 2nd, 2015].
CSPG Member Ticket Price: $45.00 + GST. Non-Member Ticket Price: $47.50 + GST.
Each CSPG Technical Luncheon is 1 APEGA PDH credit.Tickets may be purchased online at https:// www.cspg.org/eSeries/source/Events/index.cfm.
ABSTRACT
Cenozoic volcanism and sedimentation in the western U.S. and Mexico occurred under extensional to transtensional strain regimes, resulting in excellent preservation of stratigraphy in deep, fault-controlled basins. At ~50-16 Ma, fallback of the subducting Farallon slab resulted in long-distance westward-migration of arc front volcanism across the southwest US and western Mexico, accompanied by E-W extension and basin development. Initially (pre-22 Ma), Farallon slab fallback caused asthenospheric upwelling,
producing supervolcano silicic caldera fields in the east, including the Sierra Madre Occidental silicic large igneous province. Our new work there shows that extension accompanied the ignimbrite flareup and swept westward with it, producing the largest epithermal gold province on Earth.
Continued Farallon slab fallback at ~22-16 Ma produced stratovolcano/lava dome chains on thinner crust in the west, including the Sierra Nevada Ancestral Cascades arc and Comundú arc, in Alta and Baja California, respectively. By ~16-12 Ma, the Pacific/North America plate boundary lengthened, causing E-W extension over a broad arc/backarc region in the southwest U.S. and Mexico (northern and southern Basin and Range).
Thermal softening weakened the continent in the arc front, just inboard of a strong lithospheric block created by the Cretaceous batholith in Alta and Baja California. This became exploited by focused NNW-SSE transtension at ~12 Ma, in response to a change in Pacific plate motion, from more westerly to more northerly. Baja California was quickly rifted off of North America at 12-6 Ma, due to stalling of large Farallon microplates, but extension in Baja basins has continued during the “drift” phase.
California is calving off more slowly, following northward migration of the Mendocino triple junction (MTJ). The onset of transtension is marked by a burst of ~1210 Ma high-K arc volcanism. The leading tip of the transtensional rift exploited a series of large arc volcanic centers localized at major transtensional stepovers (Sierra Crest-Little Walker, Ebbetts Pass), presently occurring at Mount Lassen; in its wake, the largest rift volcanic centers (Long Valley, Coso) are
localized in transtensional stepovers.
This talk will focus on distinguishing sedimentary, volcanic and structural features of basins formed under the tectonic regimes described above
Cathy Busby has been a professor at the University of California for 32 years. Her B.S. is from Berkeley, and her Ph.D. is from Princeton, both in Geological Sciences. Cathy is a field-based geologist, doing research in sedimentology, volcanology, and structural geology, in convergent margin and rift tectonic settings. Her work is mainly sponsored by the National Science Foundation, but has also been supported by the geothermal, mineral and petroleum industries, and the U.S. Geological Survey. Most recently, Cathy has become involved in oceanographic research, serving as Co-Chief Scientist on International Ocean Discovery Program Expedition 350 to the Izu-Bonin arc (2014). Cathy teaches short courses and field workshops on sedimentary tectonics, deepwater sedimentation, and volcanic-volcaniclastic geology. Cathy’s two offered talks will focus on the two main themes of her current NSF-funded research.
SPEAKER
Mark A. McCaffrey, Ph.D. Weatherford Laboratories11:30 am
Tuesday, April 21th, 2015 Calgary, TELUS Convention Centre Macleod Hall C/D Calgary, Alberta
Please note: The cut-off date for ticket sales is1:00 pm, three business days before event. [Thursday, April 2nd, 2015].
CSPG Member Ticket Price: $45.00 + GST.
Non-Member Ticket Price: $47.50 + GST.
Each CSPG Technical Luncheon is 1 APEGA PDH credit.Tickets may be purchased online at https:// www.cspg.org/eSeries/source/Events/index.cfm.
ABSTRACT
“Gas Fingerprinting” refers to using the composition of a gas as a tool to resolve various exploration and development problems.Two characteristics of a gas define the gas “fingerprint”:
(i) the molecular composition of the gas (i.e., how MUCH of each gas species is present – e.g. methane, ethane, propane, butanes, CO2, N2 etc.) and
(ii) the isotopic composition of the gas (i.e., the abundances of the stable isotopes of carbon and hydrogen in each gas species).
The primary applications of gas fingerprinting to exploration and development of petroleum in unconventional oil and gas reservoirs are:
• Determination of reservoir thermal maturity (constraining the likelihood of associated hydrocarbon liquids).
• Assessment as to whether or not induced fractures have propagated out of the intended zone and into either an overlying or underlying zone causing the unintended commingling of production from multiple intervals.
• Quantitative allocation of the contribution of individual pay zones to commingled gas production.
• Assessing the origin of hydrocarbon gas in aquifers to determine if such gas is, or is not, related to petroleum development activity in an area.
Additional applications of gas fingerprinting to conventional reservoirs:
• Determination as to whether or not the gas in each penetrated interval is bacterial or thermogenic in origin (greatly constraining the likelihood of associated hydrocarbon liquids).
• Prevention of “missed pay” (e.g., pay zones could be missed where they have been flushed by drilling while overbalanced, but isotope data identify when an interval contains migrated gas, even if the drilling conditions prevent the migrated gas from appearing clearly on well log data).
• Characterization of hydrocarbon type in a zone (gas, condensate, or oil).
• Identification of reservoir compartment boundaries.
Weatherford Laboratories scientists have developed tools for deriving the maximum information from gas fingerprinting data by thoroughly integrating gas compositional and
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isotopic data with each other and with geological and engineering data. This talk will use case studies to illustrate such applications of gas data. Both laboratory-based and well-site-based gas analyses will be discussed.
Dr. Mark McCaffrey is the Geoscience Manager of Interpretive Services at Weatherford Laboratories. He received his B.A. (1985) from Harvard University, magna cum laude with highest honors in geological sciences, and his Ph.D. (1990) in chemical oceanography (in the area of organic geochemistry) from the Massachusetts Institute of Technology/ Woods Hole Oceanographic Institution Joint Program. Mark spent 10 years at Chevron and Arco as a petroleum geochemist, then founded OilTracers LLC, a firm specializing in applications of petroleum geochemistry. After 10 years, OilTracers was acquired by Weatherford. He is an author of more than 30 articles on the application of geochemistry to petroleum exploration, reservoir management, and paleoenvironmental reconstruction. As an Expert Witness he has testified (i) in Mississippi State Court, (ii) in Ohio Federal Court, (iii) before the Oklahoma Corporation Commission, and (iv) before the Texas Railroad Commission.
Have you been a CSPG member for 30+ years (since 1985)?
If so, watch your email inbox for your invitation to the 15 th Annual CSPG Long-Time Members Reception. The popular event is a cocktail party organized exclusively for our more senior members, in appreciation of their long commitment to the Society.
Attendance is by invitation only.
Tuesday, May 5, 2015 | 5:30pm – 7:30pm | The Fairmont Palliser, Alberta Room
SPEAKER
Krzysztof M. (Chris) Wojcik
AAPG Distinguished Lecturer 11:30 am
Tuesday, May 26th, 2015 Calgary, TELUS Convention, Macleod Hall C/D Calgary, Alberta
Please note: The cut-off date for ticket sales is 1:00 pm, three business days before event. [Thursday, May 21st, 2015]. CSPG Member Ticket Price: $45.00 + GST. Non-Member Ticket Price: $47.50 + GST.
Each CSPG Technical Luncheon is 1 APEGA PDH credit.Tickets may be purchased online at https:// www.cspg.org/eSeries/source/Events/index.cfm.
ABSTRACT
Seismic amplitude anomalies have been used for over 40 years to identify and derisk exploration opportunities with a great degree of success. Beginning in the late 90s, the global industry portfolio of solid amplitude-supported opportunities started to get depleted in many basins. The depletion of high-confidence opportunities resulted in drilling of intrinsically riskier amplitude anomalies leading to significant exploration failures and unexpected outcomes. Some of the failures involved non-commercial hydrocarbons (low-saturation gas or residual gas), some involved anomalous lithologies (e.g. marl, ash or high-porosity wet sand) and some appeared to be related to seismic artifacts.The exploration community realized that seismic anomalies have to be rigorously verified and evaluated within a correct geological context to facilitate realistic risk assessment.
Detecting amplitude or AvO anomalies is always a significant factor in prospect evaluation. True and robust DHI’s have
large impact on prospect chance of success and drill or not drill decisions. Thus any detected seismic anomalies are sometimes streamlined as true DHI’s, creating high expectation and potentially resulting in spectacular failures. The learning from successes and failures demonstrates that potential DHI’s must be tested against a broad range of subsurface scenarios and the results must pass the consistency test against geological expectations. At a highlevel, the DHI evaluation process should include four steps:
• DHI detection – constrained by previous knowledge of rock properties system and seismic analogues to define detection strategy
• DHI detection – constrained by previous knowledge of rock properties system and seismic analogues to define detection strategy
• DHI verification – inspection of pre-stack data and qualitative AvO interpretation carried out in a context of reservoir/seal stratigraphy and possible trapping configurations
• DHI assessment – detailed comparison of the observed and predicted seismic response for full range of subsurface scenarios with sensitivity analysis and quantification of scenario likelihoods Fluid contact analysis – focused on geophysical and geological consistency and reduction of volumetric uncertainties
The results of detailed quantitative interpretation studies are integrated with independent geologic risk and confidence level assessments. Good quality 3D seismic data facilitate rapid multi-attribute AvO classification and probabilistic chance factor updates. The process is guided by scenario-based forward modeling based on applicable predictive frameworks and with considerations of success and failure outcomes. This paper presents several examples of volume and scenario-based DHI assessment workflows from selected Circum-Atlantic basins, with discussion of underpinning rock properties systems and lessons learned from drilling results.
Krzysztof M. (Chris) Wojcik currently holds a position of Geophysical Advisor with Deepwater Exploration in Shell Americas in Houston. Chris has MSc degree in Geology from the Warsaw University and PhD in Sedimentary Petrology from the University of Kansas.
Chris specializes in application of Quantitative
Interpretation technologies in conventional exploration and is one of Shell’s global experts in the area of DHI assessment and integration with prospect risking. He had several exploration and technology assignments in Gulf of Mexico, Angola, Nigeria, Norway, Brazil, Guyanas and worked in many other deepwater basins. Chris was involved in a number of Shell’s discoveries over the last two decades and his is principal interest is detection of hydrocarbons with seismic methods. His areas of interest include the following:
• Geologic controls on elastic rock properties and AvO response
• Integration of geology and geophysics into scenario-based predictive workflows
• Multi-attribute interpretation and DHI detection with 3D seismic data
• Probabilistic assessment of exploration risks with seismic methods
Chris is also involved in teaching and coaching of new generations of explorers and geoscientists.
SPEAKER
Kent Barrett
Laricina and Ghislain De Joussineau, Beicip Inc., France
12:00 Noon
Thursday, April 2, 2015
Schlumberger, Second Floor Lecture Theatre
Palliser One Building 125 - 9th Ave S.E., Calgary AB
ABSTRACT
The Laricina Energy pilot at Saleski has produced 500,000 bbl of bitumen (79,400 m3) since the commencement of steam injection
in December, 2010. Over time and through experimentation it was determined that Cyclic SAGD in horizontal wells was the most effective means of bitumen production from the dolomite of the Grosmont Formation.
Vertical permeability is critical to any steam recovery mechanism for bitumen recovery. The permeability of the Grosmont Formation is dictated by fracture density. In order to better understand variations in production along producing horizontal wells and to assist reservoir analysis and simulation studies, a good understanding of the nature of the distribution of fractures within the reservoir was required.
In 2013, Beicip Inc. of Paris, France was engaged to provide a fracture model of the Saleski Grosmont reservoir. Over a period of weeks a team of geologists and then engineers travelled to Calgary to work on this project. They began by conducting detailed fracture descriptions of six 60m long cores from the study area. They then reviewed 20 image logs derived from vertical wells around the pilot. One recent horizontal well drilled in 2014 was subsequently added to the interpretation.
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Drilling fluid losses data and production data were also incorporated. The VVAZ processing of seismic data also provided insights to the fracture interpretation.
A NE-SW trending tectonic fracture set was identified based on image logs and seismic. It is interpreted to be related to the complex burial and uplift history involving two orogenies and one episode of continental glaciation downwarping and post-glacial rebound
Most fractures are not tectonic but instead are subvertical cracks formed by differential compaction around solution voids created by early Cretaceous karsting. They are randomly oriented but their abundance is controlled by reservoir facies. Many of these formed during the karsting event and have undergone solution enlargement that has enhanced their contribution to reservoir porosity as well as permeability. Western Canada Geological Edge Set Northern US Rockies & Williston Basin Geological Edge Set
US / Appalachian Basin Geological Edge Set
Western Canada: Slave Point, Swan Hills, Leduc, Grosmont, Jean Marie, Horn River Shales, Elkton, Shunda, Pekisko, Banff, Mississippian subcrops and anhydrite barriers in SE Sask., Bakken, Three Forks, Montney, Halfway, Charlie Lake, Rock Creek, Shaunavon, BQ/Gething, Bluesky, Glauconitic, Lloyd, Sparky, Colony, Viking, Cardium, CBM, Oilsands Areas, Outcrops
US Rockies & Williston: Red River, Mississippian subcrops & anhydrite barriers (Bluell, Sherwood, Rival, etc), Bakken, Three Forks, Cutbank, Sunburst, Tyler, Heath, Muddy, Dakota, Sussex, Shannon, Parkman, Almond, Lewis, Frontier, Niobrara, Mesaverde shorelines, Minnelusa, Gothic, Hovenweep, Ismay, Desert Creek, Field Outlines, Outcrops
Texas & Midcontinent: Granite Wash, Permian Basin paleogeography (Wolfcampian, Leonardian, Guadalupian), Mississippian Horizontal Play, Red Fork, Morrow, Cleveland, Sligo/Edwards Reefs, Salt Basins, Frio, Wilcox, Eagleford, Tuscaloosa, Haynesville, Fayeteville-Caney, Woodford, Field Outlines, Outcrops, Structures
North American Shales: Shale plays characterized by O&G fields, formation limit, outcrop, subcrop, structure, isopach, maturity, stratigraphic crosssections. Includes: Marcellus, Rhinestreet, Huron, New Albany, Antrim, UticaCollingwood, Barnett, Eagleford, Niobrara, Gothic, Hovenweep, Mowry, Bakken, Three Forks, Monterey, Montney, Horn River, Colorado
Eastern US / Appalachia: PreCambrian, Trenton, Utica-Collingwood, MedinaClinton, Tuscarora, Marcellus, Onondaga Structure, Geneseo, Huron, Antrim, New Albny, Rhinestreet, Sonyea, Cleveland, Venango, Bradford, Elk, Berea, Weir, Big Injun, Formation limits, Outcrops, Allegheny Thrust, Cincinatti Arch, Field outlines
Texas & Midcontinent US Geological Edge Set
Mexico Geological Edge Set
Mexico: Eagle Ford-Agua Nueva, Pimienta, Oil-Gas-Condensate Windows, Cupido-Sligo and Edwards Reefs, Tuxpan Platform, El Abra-Tamabra facies, Salt structures, Basins, Uplifts, Structural features, Sierra Madre Front, Outcrops, Field Outlines
Deliverables include: -Shapefiles and AccuMap map features -hard copy maps, manual, pdf cross-sections -Petra Thematic Map projects, GeoGraphix projects, ArcView map and layers files
-bi-annual updates and additions to mapping -technical support
SPEAKER
Ashton Embry
Geological Survey of Canada, Calgary, aembry@nrcan.gc.ca
12:00 Noon
Tuesday 14th April, 2015
ConocoPhillips Auditorium, Gulf Canada Square, 401 - 9th Ave. S.W. Calgary, AB
ABSTRACT
Crockerland is conceived as an allochthonous terrane which accreted to the Laurentian margin in the Devonian and remained an important source area until the latest Triassic. The history of Crockerland has been interpreted from tectonic analyses, facies analyses, sediment composition, and ages of detrital zircons. The Crockerland Terrane originated to the east as a fragment of fused Baltica and Laurentia crust on the basis of the common occurrence of both Timanide (500-700 MA) and Caledonide (440-420 MA) zircons in Late Devonian sandstones.
The initial docking of Crockerland occurred in earliest Devonian and the final convergence of Crockerland and Laurentia occurred near the Devonian- Carboniferous boundary (Ellesmerian Orogeny). In Early Carboniferous, the highly deformed portion of the former Laurentian margin was affected by extension and the post-Devonian history of Crockerland is recorded in the sediments of the Sverdrup Basin.
In Permian and Triassic substantial amounts of siliciclastic sediment, derived from Crockerland, were deposited in Sverdrup Basin. Late Triassic sandstones contain numerous detrital zircons of Middle Triassic and Carnian age, indicating that the drainage systems stretched all the way to the tectonically active, Pacific margin of Crockerland. Sediment influx reached a zenith in the Late Triassic (Norian) when Crockerland-derived, siliciclastic deposits were up to a kilometre thick and extended over the entire Sverdrup Basin.
In latest Triassic, following an episode of widespread tectonic uplift, sediment input from the north became very minor. It is interpreted that a rift developed between Crockerland and the Sverdrup Basin in the early Rhaetian resulting in a disruption of regional drainage patterns and a huge reduction of sediment supply. Such rifting represented the initiation of the Amerasia Basin. The rifting of Crockerland away from the Sverdrup Basin, continued throughout the Jurassic and earliest Cretaceous as the Amerasia Basin slowly opened by hyperextension of continental crust. The ages
of detrital zircons from northerly-derived, Jurassic and earliest Cretaceous sandstones indicate that only local streams from nearby rift shoulders (Sverdrup Rim) supplied the northern margin of the Sverdrup Basin. In Early Cretaceous, sea floor spreading began in the Amerasia Basin and the fragments of Crockerland were further dispersed and buried by sediment. These fragments now form the basement of: 1) portions of the northern Amerasia Basin, 2) the ChukotkaEast Siberia continental margin of Russia, and 3) Chukchi Borderland.
Ashton Embry did his graduate studies on Arctic Devonian strata at the University of Calgary in the late 60s and early 70s and worked for four of the “seven sisters” in the oil patch. For the last 38 years he has worked with the Geological Survey of Canada as a regional stratigrapher responsible for the Mesozoic successions of the Arctic Islands. Last year he became an emeritus scientist with GSC..
BASS Division talks are free. Please bring your lunch. For further information about the division, joining our mailing list, a list of upcoming talks, or if you wish to present a talk or lead a field trip, please contact either Steve Donaldson at 403766-5534, email: Steve.Donaldson@cenovus. com or Mark Caplan at 403-975-7701, email: mcaplan@atha.com or visit our web page on the CSPG website at http://www.cspg.org.
SPEAKER
Bob Mummery
Wednesday 15th April, 2015
Over ten years ago I had the opportunity to undertake some field work in North Korea for a JV group out of Singapore who had been awarded the first onshore exploration block in North Korea (DPRK). I will share some of the geological work available to me from both Russian & DPRK sources and my own observations of the hydrocarbon potential of onshore North Korea based on my travels to the concession area.
Topic and format to be confirmed. We are recruiting a speaker to provide a financial perspective of the current International Exploration business.
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Please contact Kevin Morrison or Jurgen Kraus for more information.
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SPEAKER
William Arnold Ingelson, APS Member
7:30 pm
April 17, 2015
ConocoPhillips Auditorium, Gulf Canada Square, 401 – 9th Ave. S.W. Calgary, AB
ABSTRACT
On two recent trips to New York City, the dinosaur display at the American Museum of Natural History held a special interest. In his presentation, Arnold will share a number of photographs and descriptions of Alberta dinosaurs collected during the first three decades of the 20th century. These original specimens represent a significant number of dinosaurs collected by Barnum Brown and the Sternberg family during the so-called
Great Canadian Dinosaur Rush. Methods of displaying these original specimens will also be shared.
Arnold Ingelson is a native Calgarian and has been involved in searching for fossils and dinosaur bones for the past five decades. As a young boy, his uncle, Bill Downton, one of the founding members of the Calgary Rock and Lapidary Club would take Arnold & his younger brother Allan, on field trips to the Badlands. This inspired a life-long interest in both paleontology and landscape painting. Following high school, Arnold pursued a Bachelor of Education from the University of Calgary majoring in Secondary Art. Arnold also completed three diplomas in the areas of Speech Arts and Drama from Trinity College of London, England, the Royal Conservatory of Toronto and Mount Royal College. This provided the opportunity to teach Speech Arts for a number of years at Mount Royal Conservatory. He later completed a Masters in Educational Leadership from the University of Portland, Oregon.Arnold taught at both the elementary and secondary levels in a career spanning 34 years with the Calgary Board of
Education. He was Principal at five different schools prior to his retirement in 2012.
Arnold has continued his passion of painting as well as paleontology during his retirement. He and his wife also have a strong interest in travelling throughout the world. His recent trips to the American Museum of Natural History form the basis for this presentation.
This event is presented jointly by the Alberta Palaeontological Society, the Earth Science Department of Mount Royal University, and the Palaeontology Division of the Canadian Society of Petroleum Geologists. For details or to present a talk in the future, please contact CSPG Palaeontology Division Chair Jon Noad at jonnoad@hotmail.com or APS Coordinator Harold Whittaker at 403-286-0349 or contact programs1@albertapaleo.org. Visit the APS website for confirmation of event times and upcoming speakers: http://www.albertapaleo.org/
Petrophysical Reservoir Characterization
Porosity Determination
Variations in matrix density can cause significant errors in the porosity calculation by assuming a static matrix density. Using the methods are previously mentioned, the matrix density of 2706 kg/m3 was determined and used for density-porosity calculation in well O1. A depth shift of 2.83 m is required to match the core depth to density log depth. After depth shift, the log-derived bulk density and routine core porosity with depth demonstrates a good correlation between these parameters (Fig. 8)
8 A comparison of grain density from the core and RCA on plugs porosity versus depth
Three samples of XRD have been collected; in general the samples have a similar mineralogical composition (Fig. 9). The average of the chemical analysis for quartz is 35%. The dolomite content increases with depth with an average of 20%. The potassium content within the study core is 12% for muscovite and 18% for K-feldspar.The average of the pyrite and albite content are 2% and 4%, respectively.
This indicates that the K-feldspars contribute the largest proportion to the potassium content of the formation. The illite occurs in trace amounts (1.5–2%). The author believes that the illite content probably was underestimated due to the difficulties in distinguishing between the illite and the muscovite using the bulk XRD.
A correlation after the core was depth-shifted of the density porosity to the core porosity; and the sonic porosity to the core porosity is shown for the unit of the studied well in (Fig.10). Although the both correlations are poor, the correlation of the density porosity with core porosity is slightly better than the
correlation of the sonic porosity with core porosity. The similarity of the density and sonic porosities values may indicate that no micro-fracture is present in the core interval. In general, MnC is characterized by intergranular porosity, with some micro-porosity.
Fig. 9 XRD mineralogy analysis by weight % for the three samples based on data from Bustin (2009). The results shows values for quartz, dolomite, pyrite, orthoclase and calcite, but the results are less accurate for muscovite and illite
Fig. 10 Weak correlation of the 27 sample points of core plug samples versus density and sonic porosity for unit MnC. The density porosity with core porosity shows better correlation compared to the sonic porosity with core porosity
Fig. 11 A comparison of bulk-density log and RCA on plugs porosity versus depth. The averages of variation between both the porosity measurements were acceptable within a range of 0.5 to 1 porosity unit
A comparable response between the core porosity and log bulk-density is noted (Fig. 11) Also, a similar trend was observed between the porosity derived from bulk density and the core porosity (Fig.12). Porosities vary
from 4.4% to 8.7% for the core measurement, while porosities vary from and from 4.4% to 11.7% for log measurement. The average porosity was 5.4% with standard error band of +/- 0.5 porosity unit from wireline log measurement.
Fig. 12 A comparison of log-derived porosity from the density log and RCA on plugs versus depth
Porosity and Permeability Relationship
Although a good trend is noted, the correlation between the density porosity and averaged probe permeability is weak. The density porosity (calculated using a matrix density of 2706 kg/m3) is compared to profile permeability of the seven point average as mentioned. The density porosity trends generally match probe permeability values (Fig.13)
Fig. 13 A comparison of density porosity values and averaged profile permeability (7 points), Well O1. The density porosity trends generally match profile permeability values
Pore-throat Radius and Flow Unit Identification
Using the permeability correction derived from pulse-decay data measured at estimated reservoir NOB pressure, the averages of the pore throat apertures from the Winland rp35 plot suggest that the values lie between the 0.05 and 0.1 micron (µm) despite a wide variation in porosity. As a result, the scale of nano-pore sizes dominates rather than porosity control the flow in the study reservoir and impacts production from the tight gas of the MnC.
(... Continued on page 16)
Fig.Despite a wide variation in porosity, the relationship between the permeability, porosity and pore throat shows that only one flow unit was identified, but some errors can be expected without taking lithologydependent compressibility into consideration (Fig. 14). Some of the data that lies outside of the range of 0.05-0.1 µm lines may reflect the lithology-dependence of stress (Clarkson et al., 2012). As a result, the dominant pore throat dimension and the porosity control the flow speed and capacity in reservoir rock and also help to identify the rock quality.
Fig. 14 The Winland’s cross plot of corrected for in-situ stress probe permeability data versus density porosity along with lines based on Aguilera Equation,Well O1.The scale of nano-ports size dominates in the study reservoir. The relationship between permeability, porosity and pore throat shows that only one flow unit was identified
In the studied zone, the MLP plot of the log derived porosity versus the probe permeability for the core intervals indicate homogeneity despite the fact that it is not in the form of a 45-degree line. The presence of only one flow (no inflection points) is indicated (Fig. 15). The results confirmed in the definition of one flow unit from the Winland plot, and also that the porosity is not the main factor to control the permeability despite of the presence of different wide range of storage capacity.
Fig. 15 Modified Lorenz Plot shows a cumulative storage capacity versus cumulative flow capacity from density porosity and profile permeability (7 point averages). The MLP indicates that the presence of only one flow unit (no deflection points was notified)
Using D-S method, water saturation measurements were found to be less than 20%. In the tight gas reservoir, the DeanStark method is inadequate to capture the heterogeneity changes at a fine scale; it is also inadequate for dry cores.
Nieto et al. (2009) prefer the core analysis method and obtained good results. They
established a relationship between core porosity and Dean-Stark saturation (resistivity independent). In their study case method, the average water saturation values from the core are close to the water saturation values gained from logs by using Archie’s equation parameters which are assumed to be comparable with core analysis.The average water saturation value is found to be around 14% (Fig. 16).
Fig. 16 A plot of Dean-Stark water saturation determination and log-based water saturation estimates, well O1
The Montney Fm was deposited as a series of siltstone and shale cycles. An understanding of the sub-petrofacies architecture of the distal shelf and slope deposits was built up from the well log and core data. The Montney Fm contains extremely low-permeable laminations of shale and siltstone.
Petrofacies 3 (phosphatic Montney) is recognized in the study area and has been determined through core and log analysis to be characterized by laminated sediments and finer grain size. Although, the resistivity has a very slight impact on determination of subpetrofacies, we distinguished that in addition to the rock type, gamma ray and density porosity are fully capable of determining the sub-petrofacies.
In general, the average value of resistivity log is the highest in sub-petrofacies 3, while the lowest average value was noted for subpetrofacies 1. The gamma ray trend from the high value in sub-petrofacies 1 to the low values in sub-petrfacies 3. The plot of the density porosity versus the gamma ray and resistivity shows the petrophysical characteristics for the different sub-petrofacies in the studied core (Fig. 17)
The sub-petrofacies were determined by using a threshold (cut-off) technique. Table 1 shows the log threshold values for the subpetrofacies determination for the studied core. Further, an attempt was made to link the core observations and the well productivity by integrating the core description with the petrophysical measurements of the core intervals. The importance of this discussion was to link these sub-petrofacies to the well productivity (Fig. 18)
Fig. 17 Petrophysical characteristics for the different sub-petrofacies based on the cut-off values of the logs on the cored interval, Well O1. Maximum porosity accompanied with SP 3 and minimum porosity in SP 1. GR trend decrease from SP 1 to SP 3, and resistivity threshold values (1, 2 & 3) shows that the highest average of resistivity is in SP 3 and the lowest in SP 1
Table 1 Hydraulic rock type by threshold value of porosity, permeability and lithology within 0.5 µm pore throat size for the studied core, well O1
Fig. 18 Determination of the reservoir distribution using an integrated geological description, core measurements and petrophysical properties
Sub-petrofacies (SP1) to Sub-petrofacies (SP3) are located in the studied core of Well O1. The petrophysical measurement of the core can be used to bridge the gap between the core and well productivity. Subpetrofacies (SP3) contains very fine sandstone and siltstone. The porosity of sub-petrofacies (SP3) is also the highest among that of the three petrofacies and represents the best reservoir rock in the studied core. It has the highest porosity ranging from 6.8% to 10% and permeability ranging from 0.0007 mD to 0.0045 mD.
Sub-petrofacies (SP2) represents the shaly-siltstone with ripple laminations and
bioturbation. It represents the reservoir rock with a relatively high porosity. The porosity ranges from 4.6% to 6.8%, and the permeability ranges from 0.0005 mD to 0.003 mD. A Subpetrofacies (SP1) is mostly a shale interval with a ripple lamination and occasionally it is extensively bioturbated, however, it represents a reservoir rock with a porosity of less than 4.6%, and a permeability ranging from 0.0004 to 0.002 mD.The porosity of this sub-petrofacies is the least among all the three petrofacies. Petrophysically, it represents the poorest quality reservoir in the core (Derder, 2012).
In general, the sub-petrofacies in the studied core were assigned by combining all available geological and petrophysical information. In the studied unit, the midpoint of the GR, resistivity and porosity are considered to be boundaries of the units. Sub-petrofacies and log responses for the studied unit (MnC) of the non-cored interval in the studied well are shown in (Fig. 19)
A slight difference was noted in general petrophysical properties of the three subpetrofacies. However, separating the reservoir into different petrofacies based only on the petrophysical analysis can lead to an incorrect estimation of reservoir properties. Consequently, an accurate estimation for the reservoir properties requires the integration of the core data to the petrophysical properties. Table 2 summarizes the subpetrofacies and estimated cut-off values for the studied unit.
Fig. 19 SP1, SP2 and SP3 shows the ranges for each sub-petrofacies over the non-cored interval in the MnC, Well O1. 1, 2 and 3 are the average values for the logs (GR “green”, Res. “brown” and Porosity logs “blue”) were assigned for each sub-petrofacies. Sub-petrofacies SP3 indicates better reservoir properties. Sub-petrofacies SP1 has a lower reservoir quality
Table 2 Log threshold petrophysical values assigned to recognize petrofacies for MnC interval of the well O1
The non-pay intervals within the gross interval were excluded by using porosity and permeability cutoff values. The porosity and permeability cut-off values were established through the calibration of wire-line logs to the core data. Based on the values for the calculated average permeability (kc) and calculated average porosity (Øc) of the three different sub-petrofacies, the cross-plot of porosity versus permeability was divided into four regions.
Jensen and Menke (2006) used a probabilistic approach to estimate the accuracy and errors of various porosity cut-off values. This was accomplished by shifting the Øc line. Alternately, in this study the kc line has been shifted instead to minimize the errors and to get the best estimation of the permeability cut-off value, which is called (kBE). The approach is based on defining four regions; A, B, C and D in the log(k)–Ø (Fig. 20), where the region boundaries are identified by the threshold values of average permeability (kc) and average porosity (Øc).
Fig. 20 Cutoff value estimation using the relationship between k and Ø for the core samples.The Kc line (blue) is shifted to minimize the errors and get best estimation of the permeability cut-off value KBE (red). The dotted lines indicate the standard error band from the average permeability KBE is within range of (± 0.00066 mD)
Region (A) represents a non-pay zone (k<kc & Ø<Øc) of the data identified using kc and Ø. In contrast, region (D) represents a net pay zone (k>kc & Ø>Øc) of the data identified using kc and Ø. Regions (B) and (C) represent erroneous misidentifications where (k>kc & Ø<Øc) or (k<kc & Ø>Øc) respectively for non-pay of pay zones and of pay for non-pay.
The probability that an event, for example A, occurs is defined as prob (A) and may be calculated as the number of points that are in the area A to the total points displayed in the cross-plot. The probabilities of events B, C, or D, are thus defined as prob (B), prob (C), and prob (D). In other words, the probability error is the ratio of the number of the sample points in (A), (B), (C) or (D) divided by the total number of sample points.
The best estimates for Øc to minimize the errors of mistaking pay for non-pay and nonpay for pay and to delineate net pay intervals
were obtained by minimizing the sum of the probabilities of (B) and (C) or maximizing the sum of the probabilities of (A) and (D). The best estimate of Net-to-Gross-ratio (NTG) requires selecting Øc with equal probabilities of regions (B) and (C); regardless of their magnitudes, in order for the errors to cancel out in the misidentified regions (B) and (C).
By combining all the core data, petrophysical and statistical analysis, the conclusion was to use the Øc and kBE as cut-off values. Utilizing Øc and kBE gives the best estimate for NTG. The best estimate of permeability is to use kBE rather than kc, which are 0.00125 mD and 0.0016 mD, respectively. The standard deviation from the average of the permeability kBE is within a range of (± 0.00066 mD).
Table 3 summarizes the different values of Øc, kc, and kBE with their error rate (probability of making an error for regions (B) and (C)). In the study well, the cut-off porosity and permeability are estimated to be 5.4%, 0.00125 mD, respectively. Therefore, the NTG of the MnC unit for the core interval is estimated to be 0.39 (Fig. 21)
Table 3 Demonstrates the different estimation for KC, KBE and ØC for the studied core, well O1
Fig. 21 The Net-to-Gross ratio has been estimated by using porosity and corrected permeability parameters (x-axis in log scale) for the cored interval, Well O1. (CGT) Core gross thickness, (NPT) Net pay thickness, (NTG) Net pay to gross ratio
(... Continued on page 18)
The petrofacies are defined by the corelog calibration for the reference well O1. Based on the core-log integration, the three different sub-petrofacies are noticed for the MnC unit in well O1. The correlation and extension of the petrofacies were done to the matching wells O2, O3 and O4 for a better understanding of the interpretation. The geological and petrophysical data was integrated for the reference well O1 to recognize the different petrofacies. Horizons (Montney Top, MnC Top and Bottom) were used to create the overall geometry of Unit C for the selected wells.
The results of qualitative and quantitative analysis from the reference well are taken to arrive at different well log sub-petrofacies. From the three mentioned Sub-petrofacies, reservoir attributes for very fine-grained sandstones and siltstones (Sub-petrofacies 3) at Unit C include a 11-14 m thick interval with 0.3-0.4 net to gross ratio, 5-6% average porosity, and 0.001-0.003 mD average permeability. Based on these attributes, the estimated net-to-gross are 0.35, 0.35, 0.34 and 0.34 for wells O1, O2, O3 and O4 respectively (Derder, 2014). NeoStrat® software was used to assess the quality of results and display a sophisticated cross section (Fig. 22).
Figure 22: Cross section displaying the different lithology, sub-petrofacies with thickness and estimated NTG for the entire unit of MnC for all selected wells. Reservoir attributes for Sub-petrofacies 3 (v.f.sandstone and siltstone). Logs in the display are GR and resistivity
In this study uses an integrated approach to petrophysical research and evaluation of tight gas reservoirs. This paper attempts to present a quantitative methodology to improve reservoir characterization. It also attempts to define flow unit, petrofacies, rock typing, and net pay estimation through the integration of non-routine geological data with petrophysical analysis. By utilizing this method, I endeavor to more precisely assess the reservoir properties and their distributions. These include:
• Routine core analysis performed on full-diameter core is not useful to characterize the tight gas reservoir.
• Utilizing profile permeability measurements under reservoir conditions is an effective way to evaluate the heterogeneities at scale finer than the full-diameter core volume in the tight gas reservoir.
• Fine-scale heterogeneity in the tight gas reservoir can be quantified properly by profile permeability data.
• Fine core-scale heterogeneities in the studied unit which are below the vertical resolution of the wire-line logging tools cause difficulties when scaling up the core data to logs.
• Pulse decay measurements on core plug cut at profile permeability location under reservoir conditions is useful in order to correct the profile measurements.
• Flow unit can be identified by correcting the profile permeability measurements to in-situ condition.
• In terms of the petrophysical properties, the MnC unit is characterized by an average porosity of 5.4%, average permeability of 0.00125% mD and a low water saturation of 20%.
• Three sub-petrofacies with different reservoir qualities were recognized in the studied unit. The very fine sandstone sub-petrofacies indicates better reservoir quality, while shale subpetrofacies indicates worse reservoir quality.
• Winland and Modified Lorenz Plots established that only one flow unit was identified.
• The net pay was estimated for the tight gas reservoir in the studied well using a combined geological, petrophysical and statistical approach. The systematic use of least-square regression for selecting porosity cut-off (or permeability) values from permeability cut-off (or porosity cut-off) may lead to erroneous values. A new vision is provided to select permeability cut-off and porosity cut-off values to delineate NPT and evaluate NTG.
Further work will be performed on the subject well and offset wells including petrographic work. Well-log analysis; Neural Networks (ANN) may improve prediction of permeability and evaluation of reservoir properties from wireline logs in adjacent (noncored intervals) wells.
I thank Libyan Education Ministry for all the support. Thanks to the Natural Sciences and Engineering Research Council of Canada for funding the Project, for releasing log and core data. I thank Dr. Chris Clarkson and Dr. Per K. Pedersen, University of Calgary, for their guidance for the Master Thesis. I wish to thank Roy Haigler for helpful comments during preparation of manuscript which greatly improved the readability of the paper. Finally, I acknowledge the donation of NeoStrat® software computer program to develop and perform all computations from NeoSeis Technology Group Ltd.
1. Aguilera, R., 2010. Flow Units: From conventional to tight gas to shale gas reservoirs. Paper SPE 132845 presented at the Trinidad and Tobago Energy Resources Conference, Port of Spain, Trinidad, June 27-30.
2. Aguilera, R., 2002. Incorporating capillary pressure, pore aperture radii, height above free water table and Winland r35 values on Picket Plots: AAPG Bulletin, v.86, p. 605-624.
3. Alberta Information, Alberta Atlas: Maps and Online Resources [Online], May 28, 2014, www.infoplease/atlas/region/ alberta.html.
4. Barclay, J., Krause, F., Campbell, R., & Utting, J., 1990. Dynamic casting and growth faulting: Dawson Creek Graben Complex, Carboniferous-Permian Peace River Embayment, western Canada. Bulletin of Canadian Petroleum Geology, v.38A, p.115-145.
5. Bassiouni, Z., 1994. Theory, Measurement and interpretation of well logs. Richardson, TX, USA: Society of Petroleum Engineers.
6. Clarkson, C., Jensen, J., Pedersen, P.k., & Freeman, M., 2012. Innovative methods for flow-unit and pore-structure analyses in a tight siltstone and shale gas reservoir. AAPG Bulletin, v. 96, No. 2, pp. 355-374.
7. Davies, G., Moslow, T., & Sherwin, M., 1997. The Lower Triassic Montney Formation, west-central Alberta. Bulletin of Canadian Petroleum Geology, v. 45, No. 4, 474-505.
8. Derder, O., 2012. Characterizing Reservoir Properties for the Lower Triassic Montney Formation (Units C and D) Based on Petrophysical Methods. MS thesis, University of Calgary, Calgary, Alberta, Canada (January 2012).
9. Derder, O., 2012. Rock typing and definition of flow units, Montney Formation (Unit C), West Central Alberta. InSite: 31(1): 16-21.
10. Derder, O., 2014. Well-to-Well automated Correlation: Western Canadian Sedimentary Basin, Alberta, Canada. Reservoir: CSPG, v. 41, Issue 02, pp.20-29.
11. Jensen, J., & Menke, J., 2006. Some statistical issues in selecting porosity cutoffs for estimating net pay. Petrophysics: 47(4): 315-320.
12. Kukal, G., Biddison, C., Hill, R., Monson, E., & Simons, K., 1983. Critical problems hindering accurate log interpretation of tight gas sand reservoir. SPE/DOE 11620, 1-10.
13. Moslow, T., & Davies, G., 1997. Turbidite reservoir facies in the Lower-Triassic Montney Formation, west-central Alberta. Bulletin of Canadian Petroleum Geology, v.45, No.4, p.507-536.
14. Mutti, E., 1977. Distinctive thin-bedded Turbidite facies and related depositional environments in the Eocene Hecho Group (south-central Pyrenees, Spain): Sedimentology, v. 24, p.107-131.
15. Nieto, J., Bercha, R., & Chan, J., 2009. Shale gas Petrophysics-Montney and Muskwa, are they Barnett lookalikes?. SPWLA 50th Annual Logging Symposium, the Woodlands, Texas, June 21-24, 2009, pp. 1-18.
16. Porras, J., Barbato, R., & Khazen, L., 1999. Reservoir flow units: A comparison between three different models in the Santa Barbara and Pirital Fields, North Monagas Area, Eastern Venezuela Basin. Paper SPE 53671 Latin American and Carribbean Petroleum Engineering Conference. Caracas, Venezuela.
17. Rushing, J.A., Newsham, K.E. & Blasingame, T.A., 2008. Rock typingkeys to understanding productivity in tight gas sands. Paper SPE 114164 presented at the SPE Unconventional Gas Reservoir Conference, Keystone, Colorado, USA.
18. Snyder, R., 1971. A Review of the Concepts and Methodology of Determining “Net Pay”. SPE Paper 3609, Society of Petroleum Engineers, Richardson, Texas.
19. Tiab, D., & Donaldson, E., 2004. Pertrophysics: Theory and practice of measuring reservoir rock and fluid transport properties. Oxford: Elsevier.
20. Worthington, P., & Cosentino, L., 2005. The role of cutoffs in integrated reservoir studies. SPE Res Eval & Eng 8(4), 276-290.
21. Worthington, P., 2010. Net pay-what is it? What does it do? How do we quantify it? How do we use it?. SPE Res Eval & Eng 13(5), 812-822.
Two years have passed since APEGA joined the rest of Canada’s provinces in assigning the title Professional Geoscientist (P.Geo.) to qualified Members instead of the Professional Geologist (P.Geol.) and Professional Geophysicist (P.Geoph.) titles that have been around since 1953 and 1961, respectively. Members who already held those titles in 2012 are free to retain them indefinitely or use P.Geo. after their name, if they prefer.
During the review process for the most recent revisions to The Engineering and Geoscience Professions Act in 2010 and 2011, there was very little concern expressed by the group of Members now known as Professional Geoscientists. After the fact, the Professional Geophysicists became worried. As the most recently recognized group in the APEGA family, many were concerned that dropping the G from APEGGA was actually dropping the Professional Geophysicists from the title and re-submerging them into geology.
This isn’t true of course, any more than electrical engineers were dropped when the Engineering Professions Act of 1920 was amended in 1930 to become the Engineers Act and the four divisions (civil, electrical, mining and mechanical) were dropped from the Act, and the certificates and seals of the Members. Many new engineering disciplines that emerged between 1919 and 1930, and continue to emerge today, render organizing the Association on that basis simply impractical. The same is true for the geosciences.
In the 1920s through to the early 1950s, geology was classified as a subdiscipline of mining engineering and geophysics didn’t exist yet as an applied science. In fact, geology was defined as part of the practice of engineering
in both the 1920 and 1930 versions of the Act. Geologists and geophysicists were licensed as Professional Engineers until 1961.
Geology practitioners, it should be noted, were arguing for a separate identity from APEGA’s earliest days. Geophysics practitioners began differentiating themselves in the mid-1950s, and their profession was formally recognized as being separate from both engineering and geology in 1961, when the Association’s name changed to the double-G APEGGA. Thus, the Association’s branding effectively tracked the growing maturity of the professions: the Association of Professional Engineers of Alberta, (AEPA), then APEGGA and now APEGA.
Today, we are seeing an interesting phenomenon—considerable overlap amongst geology, geophysics and engineering. The emerging specialities include the comparatively new kid on the block: petrophysics. Another emerging specialty is the practice of geomechanics. It first surfaced as a topic in petroleum engineering at the academic level in the early 1980s as a brat child of rock mechanics and geodynamics, at the time an esoteric, academic topic under the general heading of structural geology.
Geodynamics, of course, began as an academic pursuit of the geophysicists who were hot on the trail of global tectonics and the grand collision of crustal plates. After they had it figured out, the structural geologists adopted that body of knowledge, as it created a whole new way of looking at the development of mineral deposits and petroleum provinces on the continental plates themselves. Both geodynamics and petrophysics claim practitioners who are Professional Engineers, Geologists and Geophysicists. The same
argument can be made for geomatics and its stepchild, Geographic (sometimes call geoscience) Information Systems. Similar arguments can be made for geomodelling as a specialty practiced by all three professions.
Most new and promising ideas take at least 25 years to be accepted by applied geoscientists; geomechanics is no different in that respect. The applied geoscience disciplines, plus petroleum engineering and petrophysics (which is still something of an orphan) are focused on reservoir models. Reservoir models hold elements of both hydrostatics (contributed primarily by geologists and exploration geophysicists) and fluid-flow dynamics (fluid dynamics is a subdiscipline of petroleum reservoir engineering and hydrogeology). Add in the need to know how effective hydraulic fracturing operations are (microseismicity has become a subdiscipline of both geophysics and reservoir engineering) and voila! We are back to being one more-or-less happy professional family again, a la 1920.
The time has fully arrived when each of the active Members of the three disciplines need to know more about what Members in the other disciplines do and how they can communicate together more effectively. The Canadian Society of Exploration Geophysicists has begun what will undoubtedly be a highly productive relationship with the Society of Petroleum Engineers (SPE). The Canadian Society of Petroleum Geologists (CSPG) may follow the CSEG in working more closely with the SPE, largely as a follow-up to the last three Gussow conferences.
In the same vein,APEGA held a highly successful two-day workshop on wellbore stability at the 2014 APEGA Annual Conference in Edmonton, led by Dr. Maurice Dusseault, P.Eng. and Dr. Dick Jackson, P.Eng., from the University of Waterloo, along with colleagues from industry and other universities. The process will be continued in Calgary in April 2015 and will be open to all disciplines again, co-sponsored by CSPG.
All of these events enable APEGA Members to claim professional development hours, keep current with the state of the art in their scopes of practice and gain new insights into how the new, advanced concepts of emerging specialties can be applied. Knowledge is power, and there is much power to be derived from ideas developed in concert between the geosciences and related fields of engineering. After all, that is where APEGA began nearly a century ago.
The previous paper introduced the general reservoir modeling workflow. One topic was left aside though: geostatistics. It is the focus of the present paper. Geostatistics are a whole set of techniques that allow modeling properties in three dimensions (3D) by taking into account the spatial variations of these properties. The topic is large and can’t be covered in one paper. We narrowed down to kriging and simulation techniques, which are the more popular techniques by far. We also narrowed down to the modeling of rock types – and by generalization of discrete properties. Similar techniques exist for continuous properties like porosity. Once the concepts presented hereafter are assimilated, the reader will have no problem transferring them to the equivalent techniques for continuous properties.
We are interpreting reservoirs from a limited amount of data – wells and seismic mostly. To palliate to this problem, we evaluate the reservoir characteristics between data points using interpolation and extrapolation techniques. Numerous mathematical techniques exist and it is up to us to select the one(s) most appropriate to a given property type (discrete/continuous), to a specific property (facies, porosity, permeability…), to the specific geological characteristics of the studied reservoir (clastic, carbonates, channels, reefs…) and to the specific purpose of the model (deterministic model / quantifying the uncertainties).
Interpolation means evaluating the property between the available data points. It is usually a well-defined problem, as the data points limit the possible range of the property. On the contrary, extrapolation means interpreting the property beyond the last data point. It is a much more difficult problem as one can’t be sure if the trend observed around the last set of data can be propagated far past the last known value. The last section will illustrate this problem. Extrapolation problems can be turned into interpolation problems by including data on the immediate surroundings of the zone of interest (see the Figure 3 of the March paper for an example). All evaluation techniques interpolate and extrapolate at the same time. We have us to keep in mind which areas correspond more to extrapolation than
interpolation, so as to be more skeptical about the model where extrapolation prevails.
Evaluation techniques can be deterministic or probabilistic. The former give a unique solution, such as the orange geometry for horizon A (Figure 1). The later will provide multiple solutions, such as the set of possible black geometries (Figure 1). Each realization respects the input parameters, here the well picks, while showing variations between the data points. Probabilistic techniques allow taking into account the uncertainty. In Figure 1, we will never know exactly where the horizon lays between the well picks. But at least we can, and we should, quantify the level of uncertainty whenever possible.
Mathematical evaluation techniques available on our computers are useful. For example, they allow quick testing of multiple models. Also, all the input parameters can be archived and the method rerun at a later stage. But, we must never forget that these techniques are the automation of the manual evaluation techniques that we, scientists, master. As such, we should never trust blindly what computers compute for us. If the results don’t seem to make sense based on what we know about the reservoir (geological context, typical fluid characteristics, statistics at the wells…), then we must first, double-check how we used the software before eventually changing our vision of the reservoir. It must never be done the other way around. Maybe we simply didn’t use the most appropriate evaluation technique or we didn’t set its parameters correctly. Of course, no need to be extreme the other way. If everything ran as it should and the results still can’t back up the assumptions, our hypotheses might need to be updated. Figures 2 to 13 and the accompanying text illustrate this point.
Geostatistics is the largest evaluation toolbox available to us, thanks to several main types of algorithms, which can, in turn, take multiple different types of input, from the most basic
to the most sophisticated. Geostatistics are powerful because these techniques not only take into account the univariate statistics (mean value, min/max values, standard deviation…), but they also take into account how the property is varying spatially between the data points. This is perfect for modelers, as many reservoir properties vary spatially. For example, rock types will have accumulated differently in different parts of the reservoir, depending on the geological context (fluvial, marine…). Porosity might be increasing with depth because of the increasing compaction. As another example, water saturation will vary spatially depending on the fluid zone (gas, oil, water) and it might also vary depending on the distance to the contact itself (transition zone above an oil-water contact).
Variograms are the key mathematical objects used to capture the spatial variability of the data. They are input to kriging and simulation techniques.Variograms are to the understanding of spatial variability as histograms are to the understanding of univariate statistics: essential. For this reason, variograms are explained in the next section to some details so that every asset team member can understand how their reservoir modeler defined them in their project. As promised in the introduction paper though, the next section is free of any equation.
Once the notion of variogram is explained, the remainder of this paper goes through a simplified 2D dataset of a fluvial system to illustrate the results obtained by these two types of techniques.
In the next two sections, we’ll go through the modeling of a sand/shale facies distribution, first using a dense dataset (Figure 2A) and then a limited dataset extracted from the dense dataset (Figure 2B). In this section, we are focusing on the variograms that will be used with this dataset.
Figure 2 shows the different variograms that will be used in the next sections.Variograms are represented on a map either as circles (black circles, Figure 2) or as ellipses (red and green ellipses, Figure 2). By extension, 3D variograms are represented as spheres or ellipsoids. A circular variogram means that there is no preferred orientation in the data. On the contrary, the more anisotropic the ellipse is, the more elongated and narrow the facies
will be distributed in that direction. When the property is evaluated at a given empty location, the variogram being used (circle or ellipse) is centered on this location. The data points found inside the circle will have an influence on the value that will be computed at the new location. The data points outside of the variogram won’t have any impact.
Figure 2. Dense (A) and limited (B) input dataset of sand and shale + variograms used as input for kriging and simulation.
Kriging algorithms use only the input data points, which is why kriging is a deterministic technique. Simulation algorithms, on the contrary, use both the input data points and the values that were computed before moving to this location. Simulations are probabilistic in nature because the empty nodes are not populated in the same order from one realization to the next. As a result, when the time comes to populate a given location, the surrounding available data will be different from realization to realization. For more details on how the surrounding data are used, please refer to (Pyrcz and Deutsch, 2014) for example.
2D isotropic variograms are defined by their range and their sill. The range represents the radius of the circle/ellipse. The sill will be defined in the next paragraph. 2D anisotropic variograms are defined by their maximum and minimum ranges, represented respectively by the ellipse semi-major and semi-minor axes. They are also defined by a sill, as for isotropic variogram, and by the azimuth of the semi-major axis (referenced to the North; 150 degrees on Figure 2 for example). A 3D variogram is usually defined as the combination of a 2D horizontal isotropic or anisotropic variogram and a vertical range. The vertical range is much smaller than the horizontal ranges. It reflects the fact that geological properties are continuous over a large area, while they rapidly change in the direction of deposition (here referred to as vertical). A true 3D variogram
implies that the ellipsoid can have a dip and a plunge. True 3D variograms are used when we assume that the plane of deposition is not horizontal but inclined.True 3D variograms are not commonly used, but they are gaining some traction for example in oil sands project to model dipping IHS.
Variograms are defined using variogram analyzers (Figure 3 and Figure 4).The correlation found in different orientations (azimuths) is analyzed to identify the directions of the maximum and minimum horizontal ranges (Azimuths 150 and 60 degrees respectively in our dataset). For a given azimuth, the analyzer superimposes two objects: the experimental variogram and the variogram model. The experimental variogram is a succession of points computed from the input data. The variogram model is a mathematical equation that we have to adjust to the points of the experimental variogram. The circle/ellipses (Figure 2) are the spatial representations of the corresponding variogram models.
Figure 3.Variogram analyzers showing the experimental variograms for the dense dataset (Figure 2A) along the azimuths 60 and 150 degrees + variogram model for the circular variogram (A), the slightly elongated variogram (B) and the flattened variogram (C).
The modeling expert feeds two main datasets to the variogram analyzer: a set of azimuths and a set of distances between data points. The horizontal axis of the variogram analyzer represents these distances. For our dataset, we decided to compare each data point with the nearby point, if any, 400 meters away. We then do the same for a distance of 800 meters and so on until distances of 8000 meters. As a result, our experimental variograms have one point every 400 m. We did so in 10 different azimuths, of which we show only azimuths 60 and 150, the azimuths of the axes of the variogram model. For a given azimuth and a given distance, the goal is to check how two data points (= a pair) are similar. If the values of the two points making every pair are the same, the correlation is perfect and the corresponding point of the experimental variogram will be at Y=0 on the variogram analyzer. This only happens at the origin of the graph, where the distance is zero and each node is compared to itself. The bigger the distance, the lower the correlation will get, until a distance (the range) is reached beyond which there is no more correlation. At this stage, the points of the experimental variogram plateau. This plateau is the sill. For stationary and ergodic properties, the sill is the variance of the data.
A good variogram model will be one that
starts at the origin, climbs progressively until reaching a plateau equal to the sill of the experimental variogram. It is essential to properly fit the experimental variogram between the origin and the range, as this is the part of the variogram model which will have the higher influence on the results of kriging and simulation. It is also essential to capture the anisotropy of the experimental variogram: keeping an isotropic (circular) variogram while the data show anisotropy will lead to missing some important information about the property we want to predict. Figure 3 A, B and C were used for kriging and the results are respectively shown on Figure 6, Figure 7 and Figure 8. As can be seen with this dataset, different variogram shapes do indeed give some drastically different models.
Figure 4. Variogram analyzer showing the experimental variograms for the limited dataset (Figure 2B) along the azimuths 60 and 150 degrees + variogram model for the flattened variogram (C).
Adjusting a variogram model is often challenging. It is rare to have a dataset as dense as the one used here (Figure 2A). As a result, it is rare to have horizontal experimental variograms as clean as in Figure 3. Often, the data is limited and the experimental variogram difficult to interpret (Figure 4). In this example, the experimental variogram in azimuth 60 degrees even looks as if it’s a perfect sill: there are no points dipping down progressively to the origin. If this were true, it would mean that even for very short distances, there is no correlation between the values. While true for some ore deposits, this is rarely – if ever – the case in sedimentary rocks. The issue is not the geology but the dataset: the facies distribution is under-sampled and as such the first few points are not representative. In petroleum
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studies, variogram models should always start at the origin unless it can be backed up otherwise with solid geological evidences. In technical terms, we should never have any nugget effect (= variogram model not starting at zero).
The datasets and the variograms introduced in the previous section were used as input for kriging and simulation. The dense dataset is used in this section, while the limited dataset is used in the next section. Figure 5 shows the conceptual model from which the dense dataset was extracted. The limited dataset is a subset of the large one. The area represents a set of fluvial channels which flow from the North to the South along the azimuth 150 degrees. Naturally, in a real study, the truth is not known. Here, we are assuming that the well data and the geological context lead the geologist to see it is a fluvial system and the dipmeter data helped identifying the main azimuth of 150 degrees. Kriging was applied first with different variograms (Figure 6, Figure 7 and Figure 8) before simulation was run using the most elongated ellipse (Figure 9 and Figure 10).
Kriging was first done using an isotropic variogram (Figure 6), even if the variogram analyzer showed that this variogram has too short a range in the azimuth 150 (Figure 3A). After all, with such a dense dataset, why shall we worry about the preferred orientation of the facies distribution? The data will take care of everything for us with some simple interpolation! The result is good overall and the sand facies does align along North-South geobodies, which might be interpreted as large channels. These channels are, nevertheless, wider than the input ones we know the dataset is coming from.
Then, kriging is done using a variogram model matching the experimental variogram (Figure 3B). One might argue that the plateau for the azimuth 150 is lower than the plateau at azimuth 60. In a real study, this would be investigated further. The resulting model (Figure 7) is closer to what we expected. The sand geobodies are more continuous along the azimuth 150 than in the first model. As
our variogram is fitting to the experimental points, we could stop here.
The geologist insisted though that he expected the channels to be even more continuous than they are now. He asked us to see if we could find a way to make it happen. After some testing, we decided to run kriging with a highly anisotropic variogram (Figure 3C). Of course, this variogram no longer matches the experimental variogram in the azimuth 150 - our new range is much too large. The kriging results pleased the geologist though (Figure 8) as the channels are now much better defined than before, as can be seen in the rectangle area labelled 2 noted in Figure 5 to Figure 8.. In the meantime though, we start creating channel geobodies where none should exist (rectangle labelled 1, same pictures).Also, we still can’t get some channels right (rectangle labelled 3, same pictures).This channel was not sampled well enough by our wells for kriging to be able to track it
variograms as it is impossible to know which one is the most reasonable one. The shape, dimensions and orientations of the variograms is a major source of uncertainty. In many reservoir modeling projects though, studying the variogram uncertainty is not done. Instead, modelers tend to pick one variogram – here the highly anisotropic one for example – and they run numerous simulation models with it. Figure 9 and Figure 10 are examples of two such simulation realizations. Each realization respects the input data, the input facies proportion and the input variogram. But each does it by distributing the sand and shale slightly differently.
Realizations defined by simulation have considerable value as together they build a range of possible rock distributions for the reservoir. This range can then be used to run sensitivity analysis while doing well planning or reserve computations for example. Ideally, modelers should first spend time understanding the uncertainty hidden in the variograms but also in the proportions they are using. In a second step, they can use simulation to generate multiple realizations in which these different key sources of uncertainty are taken into account.
In a real project, it would make sense to carry forward at least the two anisotropic
At last, modelers should not limit themselves in matching the data strictly. It often makes sense to adjust our data analyses in light of the extra information provided to them by their team. General geological knowledge must be used to transform data into information.
Figure 5. Conceptual sand/shale distribution from which a dataset was extracted and used in this study. Figure 6. Kriging on the dense dataset –isotropic variogram. Figure 7. Kriging on the dense dataset – slightly anistropic variogram. Figure 8. Kriging on the dense dataset – highly anistropic variogram. Figure 9. One possible simulation realization among many, created using the highly anisotropic variogram – dense dataset.As mentioned earlier, the dense dataset is not realistic and one might even argue based on it that isotropic variograms are in fact good enough. To test this hypothesis, a subset made of 1/8th of points of the dense dataset has been randomly picked and kriging and simulation was run on it.
Firstly, kriging was run using an isotropic variogram. If we use the same small range than for the dense dataset, one gets an ocean of sand with a few patches of shale (Figure 11B). This is mathematically correct, but geologically implausible: it doesn’t look anything like the fluvial system we know we have. Kriging is assigning an average value – sand in this case – at all the locations too far from the input points for the variogram to include them. This is an example of problematic extrapolation that is up to us to spot and fix by changing the kriging parameters. Using a very range 10 times the size of the initial one fixes this problem (Figure 11A). Nevertheless, the model still doesn’t show any channel.
If we use the highly isotropic variogram, the model is showing some elongated geobodies that start looking like channels (Figure 12). But we are still far from the level of detail that we obtained with kriging the dense dataset (Figure 8).
with a good variogram and simulation, even this limited dataset allows us to show possible geometries for the channels that our team knows must be present. Naturally, the local variations between these two realizations are much more important than with the two realizations of the dense dataset. For example, with this dataset (Figure 13 and Figure 14), the areas in rectangles 1 and 2 change from sand to shale drastically while with the two realizations ran on the dense dataset are very similar in these areas (Figure 9 and Figure 10)
This example shows that geostatistics have the potential to create realistic models even from a small dataset.
Geostatistics techniques are powerful because they take into account both the statistics and the spatial variability of the data. They are an essential part of every reservoir modeling workflow.
Having reviewed the reservoir modeling workflow in this paper and the previous one, the next three papers will focus on the interaction between reservoir modeling and geology, petrophysics and geophysics respectively. After this, the focus will shift to the interaction between reservoir modeling and engineering.
will be discussed in the papers on geology, petrophysics and geophysics.
Several important categories of geostatistical techniques could not be presented either by lack of space. Readers interested in plurigaussian simulations can refer to (Armstrong and als, 2011), while those eager to know more about multipoint geostatistics should have a loot at (Mariethoz and Caers, 2014).
(Isaaks and Srivastava, 1990) is a good introduction on geostatistics, as are the different courses on the topic that the CSPG offers every year.
Lastly, Alberta has the chance to host one of the world’s leading teams in geostatistics: the Center for Computational Geostatistics in Edmonton, led by Professor Clayton Deutsch (www.ccgalberta.com). Each of their publications is a valuable source of information and of new ideas on geostatistics.
Armstrong, M., Galli, A., Beucher, H., Loc’h, G., Renard, D., Doligez, B., Eschard, R. and Geffroy, F., 2011. Plurigaussian Simulations in Geosciences. Springer, 2nd edition. 176 pages.
Chilès, J.-P. and Delfiner, P., 2012. Geostatistics: Modeling Spatial Uncertainty. Wiley, 2nd edition. 734 pages.
Isaaks, E.H. and Srivastava, R.M., 1990. An Introduction to Applied Geostatistics. Oxford University Press. 592 pages.
Mariethoz, G. and Caers, J, 2014. MultiplePoint Geostatistics. Wiley-Blackwell. 376 pages.
Pyrcz, M.J. and Deutsch, C.V., 2014. Geostatistical Reservoir Modeling. Oxford University Press, 2nd edition. 448 pages.
Feel free to contact us if you have questions about this paper or about the series.
Thomas Jerome, Reservoir Modeling Manager and Geologist, RPS: Thomas.Jerome@rpsgroup.com
Suzanne Gentile, Reservoir Modeler and Geophysicist, RPS: Suzanne.Gentile@rpsgroup.com
Jun Yang, Reservoir Modeler and Geologist, RPS: Jun.Yang@rpsgroup.com
On the other hand, the results of running simulation with this anisotropic variogram are very interesting (Figure 13 and Figure 14).The sand distribution in these two realizations is similar to the ones computed from the dense dataset (Figure 9 and Figure 10). It means that
Geostatistics are a vast topic that is impossible to cover in a short introduction paper. Aspects of vertical, horizontal and 3D trends as well as the declustering of input data
CSPG is pleased to announce Norbert Alwast as the recipient of the 2014 H.M. Hunter Award.
Norbert has been a member of the CSPG since 1986 and chair (often co-chair) of the CSPG Advertising Committee since 1996. During his 18 years of service he has assisted in the evolution of the CSPG Reservoir magazine and the CSPG Technical Luncheons. When he joined the committee in 1996, the Reservoir was one half of its current 8½ x 11 inch format and included perhaps five ads. Likewise, the Technical Luncheons had only two slide advertisers per luncheon, and the media was 35mm slides! Advertising in the Reservoir and at the Technical Luncheons has grown and progressed with both the times and technology and continues to generate important revenue for the society. The committee itself has also evolved with anywhere from one to six people actively participating at any one time. Their combined efforts have truly benefited the society. Dave Work initially recruited Norbert to take over the committee and for many years he was co-chair along with Tim Bird. There were times when Norbert had to run the committee as the sole member but he now works alongside
co-chair Marc Enter. He has also received assistance in numerous ways from CSPG office staff over the years. The current role of the committee is to oversee the advertising at the CSPG Technical Luncheons. Norbert’s organizational skill, attention to detail and willingness to adapt to audio-visual technologies has enhanced advertising at the luncheons over the past years.
Norbert recalls that it was Dr. Philip Simony of the University of Calgary that initially encouraged him to join the CSPG. It was the summer of 1984 and Norbert was still an undergrad and was assisting Dr. Simony in the field. They were in the remote wilderness near Valemount, B.C. on the ridge of Mount Blackman having lunch when Phil gave Norbert “The Talk.” He insisted that you can never stop learning and that you need to stay current with the latest trends and research as well as networking with your peers and joining the CSPG would be critical in this endeavor. After joining and enjoying all the benefits that the society offered its members, Norbert was only too happy to accept when Dave Work called him to see if he would like to volunteer.
While enjoyable, volunteering with the Advertising Committee has been a lot of work and often without much fanfare. With all due respect to the advertisers and their polished slide and table advertising, one of Norbert’s mantras is “when we do our job properly, no one notices: no ‘blue screen of death’, no one falls off the stage, everyone just enjoys their lunch”. Not that it was all smooth sailing… unbeknownst to most luncheon attendees, there are occasional last-minute audiovisual or other issues that need to be sorted out. Norbert’s other mantra is “if we do things last-minute, it will probably look that way, so let’s make sure it’s finalized way ahead of time.” Despite this seemingly reasonable goal, sometimes things aren’t finalized until members are walking into the luncheon venue or even after the luncheon has started. One incident - Norbert was
able to rescue one luncheon speaker when her personal laptop froze - he traded the CSPG’s advertising laptop for hers and the talk resumed within five minutes. Thankfully, this is not a common event.
Norbert was born and raised in Olds, Alberta. This south-central location presented him with numerous opportunities to visit Alberta’s geological wonders including the Foothills and Front Ranges of the Rockies, the Badlands of Drumheller and Dinosaur Provincial Park. He graduated from the University of Calgary with a BSc in Geology (1986) and has worked for the Alberta Geological Survey/AOSTRA, the ERCB, Fekete Associates Inc. and IHS Energy. Norbert is grateful to these employers as they have all supported his volunteering with the CSPG. He has received two CSPG Tracks awards (1998 and 2009) and a number of CSPG Service awards (2010-2013).
Outside of work and volunteering with the CSPG, he is busy with family and church activities. Norbert is married to Cheryl and they have three children. He is grateful to his family as they have supported his CSPG involvement over the years.
Mark your calendars, and get ready for the 2015 CSPG Mixed Golf tournament on 21st August at Lynx Ridge Golf course. The four-golfer, best-ball tournament includes a round of golf, meals, plenty of hospitality and good times, and a chance to network with your colleagues and industry sponsors. The tournament usually benefits from the pleasant August weather (the unseasonable rain last year was unfortunate!), and typically the golf course is at its finest, with the inviting fairways, smooth greens, spectacular mountains and the ever-beckoning water hazards and sand traps to capture errant golf shots.
This is a fun tournament, with balanced teams that allow all golfers to contribute to the team score, while having a great time enjoying the day and the fellowship of golfing as a team, and developing your network of geoscientists.
Please watch for further announcements, registration forms and information in the CSPG Reservoir, and make sure to register on-line at the CSPG website www.cspg.org. Register early to avoid disappointment!
We thank our previous sponsors from 2014 and look forward to the return of members, guests and sponsors to enjoy the event. A big thank you to our continuing committee members, Darin Brazel, Penny Christensen, Norm Hopkins, Adam MacDonald, Jeff Boissoneault, and co-chair Brenda Pearson.
Whether you’re exploring a basin, producing a well or completing a shale play, time is money. That’s why Weatherford Laboratories brings a suite of formation evaluation technologies right to the wellsite. Utilizing mud gas and cuttings, these technologies provide detailed data on gas composition, organic richness, mineralogy and chemostratigraphy in near real time. As a result, operators now have an invaluable tool to assist with sweet spot identification, wellbore positioning, completion design and hydraulic fracturing. We call it Science At the Wellsite. You’ll call it money well spent.
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You can address registration inquiries to David Middleton at 403-296-8844 (dmiddleton@suncor.com), or to Kasandra Amaro, CSPG Coordinator at 403-513-1234 (kasandra.amaro@cspg. org)
If you are interested in sponsoring the tournament this year, please contact Darin Brazel at darin.brazel@tgs.com.
David Middleton & Brenda Pearson Co-Chairs CSPG Mixed Golf Tournament
Applied Hydrogeology and the Petroleum Industry in Alberta Instructor(s): Morris Maccago, Tannis Sharp
Mannville Stratigraphy, Sedimentology and Petroleum Geology Instructor(s): Doug Cant
COMING SOON
Clastic Diagenesis and Reservoir Quality Instructor(s): Nick Harris
Evaluating Source Rocks in a Risk Analysis Framework Instructor(s): Nick Harris
Facies Architecture and Sequence Stratigraphy of Delta System: From Exploration to Reservoir Performance Instructor(s): Janok P. Bhattacharya
SAGD Fundamentals - Application of Core, Geology, Geophysics and Geochemistry Instructor(s): Rudy Strobl, Milovan Fustic & Daryl Wightman
COMING SOON
Natural Fractures Systems: An approach to evaluating Resource Plays Instructor(s): Paul MacKay, Hutch Jobe
Evaluation and Exploitation of Low Permeability (Tight) Carbonate Reservoirs in Western Canada
Instructor(s): Graeme Bloy
Introduction Energy Geoscience Workshop (IEG) Instructor(s): Art Irwin
CMC Research Institute’s Newell County Field Research Station Instructor(s): Kirk Osadetz
IEG Field Seminars - Drumheller, Alberta
Instructor(s): Art Irwin
The Athabasca Oil Sands Area from Basin to Molecular Scale –4D Observations from Inside the Reservoir
Instructor(s): Rudy Strobl, Milovan Fustic & Daryl Wightman
The Athabasca Oil Sands Area from Basin to Molecular Scale – 4D
Observations from Inside the Reservoir
16 - June - 15
2 days INSTRUCTORS Rudy Strobl, Milovan Fustic & Daryl Wightman PDH Credits 17 Hours
Topic(s): Oil Sands, McMurray Formation
Location: Fort McMurray, Alberta
Vehicle(s) Used: Field vehicles and jet boat
Who Should Attend: This course is recommended for geologists, geophysicists, geomodelers, reservoir and production engineers and technical managers who wish to gain insight into in -situ oil sands operations.
Why Should You Attend: Developing a 3D view of representative oil sands deposits, understanding the impact of reservoir heterogeneity on steam chamber growth and identifying challenges with associated production are important considerations for developing optima l recovery strategies?
Pre-requisites: It is recommended that participants attend the associated short course SAGD Fundamentals.
Objectives: This two day field study focuses on integrating SAGD fundamentals with reservoir characterization of the McMurray Formation.
Course Content:
Stops include outstanding 2D to 3D exposures illustrating a range of depositional environments including open estuarine, larg e scale single and stacked channel point bar deposits, multiple cut and fill channel deposits; a variety of IHS deposits; different reservoir co nfigurations including continuous, and laterally and vertically compartmentalized reservoirs as well presence and/or absence of bottom water, top ga s, top water and multiple gas and/or lean zones throughout the reservoir column.
At each stop participants will discuss risks for SAGD development and group exercises will define SAGD top and base and optim al well pair placement. Applicability and limitations of a variety of tools for subsurface interpretation and mapping will be demonstrated with a focus on geophysical logs, dipmeter, FMI, seismic, and geochemical logs. Additionally, at most stops outcrop exposures will be compare d to nearby well data. At each stop leaders will identify an existing production analog and analyse public production data in context of SAGD risks.
Additional Information:
Lunches and a group dinner are provided. Participants are responsible for their own flights and paying for their hotel room f or 2 nights in Fort McMurray. A block of rooms at the Sawridge Inn and Conference Center, has been put aside under the name CSPG for the nights o f June 15th and 16th with discounted rates. When booking return flights on June 17th, please book them for after 6:00 PM to ensure enough tim e to finish the second day activities. Please be prepared for variable weather conditions, hiking on steep slopes and wearing appropriate fi eld clothing with sturdy hiking boots. An evening seminar on the first evening, beginning at 7:30 PM at the hotel provides an opportunity for a field safety briefing, video coverage of outcrops that will be visited, recap of SAGD fundamentals and a venue for questions and discussion.
CMC Research Institute’s Newell County Field Research Station
Field Seminar Description
The purpose of this trip is to visit CMC Research Institute’s (CMC) Newell County Field Research Station (FRS) for subsurface containment and monitoring. Programs performed at FRS will be conducted by CMC in partnership with the University of Calgary and other a cademic, industrial and government partners and clients. Although the primary FRS research focus is secure carbon dioxide storage (SC S) in geological media, the results and benefits will be more widely applicable to subsurface issues of engineering conformance and containment monitoring. FRS will become a major international nexus for subsurface, surface and atmospheric scientific and engineering research and education coupled with new technology development and demonstrations. It will also serve as a major public outreach tool for SCS. FRS is located on a surface and subsurface site, kindly provided by Cenovus Energy Ltd. covering slightly more than 2.5 km2 in Newell County southeast of Calgary. The field trip also makes stops and addresses environmental changes on geological and historical time-scales, both progressive and catastrophic, some natural and other anthropogenic. More about this trip on www.cspg.org
Field Seminar Description
Part 1, Morning
The first part will be to examine the Late Cretaceous, Horseshoe Canyon Formation which outcrops in the Red Deer River Valley East of Drumheller, Alberta. The formation is comprised of mudstones, sandstones, carbonaceous shale and coals deposited in a delta pla in environment. Sequences of transgressive and regressive sedimentation are visible within the sediments exposed in the badlands topography. Examples of delta plain, estuarine channels and coal swamps will be discussed. The primary focus is to show the areal distribution and complexities of fluvial point bar deposition and IHS beds in outcrop and discuss how this affects subsurface reservoirs and production.
Part 2, Afternoon
Visit the Royal Tyrrell Museum: a Canadian tourist attraction and center of palaeontological research noted for its collection of more than 130,000 fossils. It features ten signature galleries devoted to paleontology, with 40 dinosaur skeletons. Your chance to go walking with the Dinosaurs . More about this trip on www.cspg.org
SAGD Fundamentals - Application of Core, Geology,
Based on a previous participants’ feedback the course will be followed by beer and chat (included in the price of the Short C ourse). There will be an exciting hands on workshop session at The Last Defence Lounge (LDL) operated by the Graduate Students’ Association of the University of Calgary until 7:30PM.
Who Should Attend: This course is recommended for geologists, geophysicists, reservoir and production engineers and technical managers who wish to gain insight into in -situ oil sands operations.
Objectives: This one day seminar integrates practical SAGD fundamentals with reservoir characterization of the McMurray Formation. Developing a 3D view of representative oil sands reservoirs, understanding the impact of reservoir heterogeneity on steam cha mber growth and identifying production risk are important considerations for developing optimal recovery strategies.
Course Content:
1. Discussion of regional stratigraphy, depositional models including analogues and oil migration
2. Reservoir Architecture, geometry and compartmentalization with Implications to subsurface mapping
3. IHS - origin, recognition, vertical and lateral (dis)continuity, tools for mapping and classification(s)
4. SAGD Fundamentals - impact of reservoir heterogeneity on production, principles and case studies
5. Reservoir characterization methods and uncertainties; geological, geophysical and geochemical considerations
6. Well pair placement considerations
7. SAGD Impairments - origin, geometries, recognition, mapping and solutions
8. Distinguishing Barriers from Baffles
9. Effective vs. breached caprock - geological vs. geomechanical tools and principles
10. Good mud vs. bad mud; good breccia vs. bad breccia
11. Strategics + production analogues - IHS and lean zones.
12. Analysis of post -steam core for estimating recovery factor.
Participants of this short course are encouraged to attend the associated 2 day field trip to the outstanding outcrops in the Fort McMurray area (you have a chance to register for both (Short Course and Field Seminar) choosing COMBO with discounted price)
This seminar will be complemented by an opportunity to review representative oil sands cores from operating oil sands projects. We will:
1. Compare and contrast open or outer esturine, largescale point bar, and stacked channel oil sands reservoirs of the McMurray Formation.
2. Develop an understanding of variations in reservoir quality, effects of heterogeneity, and assess some of the challenges associated with SAGD production.
Trailhead: Access to Walcott Quarry is only through guided hike because of its designation as a UN World Heritage Site. Details will be provided when you register. Hikes are currently offered by Burgess Shale Geoscience Foundation www.burgess-shale.bc.ca/guided-hikes & Parks Canada http://www.pc.gc.ca/eng/pn-np/bc/yoho/natcul/burgess/visit/randonnees-hikes.aspx
Distance: ~22 km round trip if hiking from Takakkaw Falls to Walcott Quarry and back. This is the route followed during guided hikes offered by both organizations. Elevation Gain: 850 m.
The Burgess Shale fossil site was discovered by Charles Doolittle Walcott in 1909 and has been studied off and over for more than a century. The site is worthy of its 1981 UN World Heritage Site designated protection because it provides some of the best preserved evidence of life shortly after the Cambrian Explosion, an evolutionary event during which many of the extant lineages of the animal kingdom arose. There are earlier sites around the world but few exhibit such spectacular preservation of soft body parts organisms. The Burgess Shale site has been heavily studied and there are almost as many opinions as researchers, though all would agree on its importance as a window into the evolution of early life on this planet.
Beside the Burgess Shale site, the hike also offers breathtaking views of Emerald Lake far below, the hydrothermal dolomitization pipes of Wapta Mountain (see Yoho Glacier and Wapta Mountain hikes), glacial hanging valleys, waterfalls, moraines, alluvial fans, thrust faults and associated drag folds. Yoho is a Cree expression of awe and wonderment. Participation in a guided hike to the Walcott Quarry will leave one breathless and at a loss for all words other than “yoho”.
The deposits are within the Burgess Shale at the foot of a 150m high escarpment at the edge of the Cathedral Formation which formed about 509 Ma when Neoproterozoic basement faults reactivated (Collom et al., 2009). East of the Cathedral escarpment, the middle Cambrian package consists of 600m of carbonate strata belonging to the Cathedral Fm and a similar thickness of Eldon Fm which sandwiches the much thinner an argillaceous Stephen Formation. The Cathedral Formation exhibits a number of shallow water features including stromatolites, chicken mesh anhydrite and birds eye structures (Fletcher and Collins, 2009). The latter form in fine grained carbonates when gas bubbles are trapped or the sediment is exposed to dessication and layers of sediment part; think of how mud chips curl up at the edges as they dry (Shin, 1968). These features collectively are a strong indicator of intertidal or supratidal depositional settings for the Cathedral. One can infer a slightly deeper (but still shallow shelf) setting for the Stephen Formation before it drops into the abyss off the Cathedral Escarpment. These mixed carbonate and fine grained strata all grade to west of the escarpment into a very thick package of silty to dolomitic and often slate-like shale collectively known as the Chancellor Group.
Above:The Emerald Valley, one of the most magnificent vistas within the Rocky Mountains. Note the alluvial fan emanating from Emerald Basin at the foot of The President and the thrust fault on Michael Peak. Below: Fossil Ridge as seen from Burgess Pass showing location of the Walcott Quarry.
Left:
Centre Left: The Walcott Quarry in 1999 when the Royal Ontario Museum was conducting field research.The excavated 7m thick interval is known as the Greater Phyllopod Bed. Note the buff dolomite intermingling with the grey limestone in Mount Wapta (see The Emerald Lake Hike for more information). Centre right: some of the fossils to be seen within the quarry. The organisms with skeletal material show up in relief but soft bodied fauna leave only carbonaceous and aluminosilicate (mica and chlorite) films and can be difficult to spot because of their size and the dark colour of the rock (Butterfield, 2009).
is a four eyed arthropod with elongate feelers. Bottom Centre: Anomalocaris claw. Anomalocaridids are an extinct class of arthropod that was the top predator in the Cambrian oceans and reached up to 2 m long (Whittington and Briggs, 1985). Its claws, partly mineralized, are often found where only organisms hard parts are preserved, but the body only where there is Burgess Shale type preservation. Bottom Right: The marine priapulid worm Ottoia. Preservation is so spectacular that sometimes their last meal (a small shelly fauna known as hyolithids) can be observed lining their guts.
Figure Above (from Collom et al 2009): Two interpretations of the Cathedral platform to basin transition during the Cambrian.There is a saying that if you want three opinions get two geologists in a room.The geology associated with the Burgess Shale is complex and obscured by time, faulting and exposure of variable quality.The result is that there are often conflicting interpretations associated with the shale. Even the status of the Burgess Shale as a formation is under some debate. For the sake of simplicity in this article we will refer to it as the Burgess Shale and let the issue be resolved through healthy scientific discourse.
There are also differing interpretations on the stratigraphy and the role of structure in the evolution of the stratigraphic units. An earlier interpretation based on Stewart (1993) depicted in (A) would suggest no basement structure influencing the position of the Cathedral escarpment and a broad unconformity truncating the Gog Group. In (B) more recent work by Collom et al (2009) would suggest that basement faults were active possibly into the Cambrian and controlled the position of the escarpment and the placement of stratigraphic units.The deep seated faults provided paths for mineral laden brines that supported chemotrophic communities, generated lead-zinc deposits and drove dolomitization along the margin of the Kicking Horse Rim.
The noted “megatruncation” surfaces are related to collapse events along the escarpment, triggered by fault brecciation and dissolution along hydrothermally active margins of the platform (Collom et al, 2009). “F” marks the position of the Walcott Quarry. The domes with brick pattern are carbonate mud mound build-ups created by small clusters of reef forming organisms.
One portion of the lower Chancellor Group abutting the Cathedral escarpment is mapped as the Burgess Shale Formation. While the Burgess Shale fossils occur at numerous intervals along the 100 km long Cathedral Escarpment, fossils are not preserved away from it. At the base of the escarpment are carbonate mud mounds which are associated with magnesium and barium rich brine seeps coming from the basement faults. These seeps form dense pools in topographic lows in the ocean floor and provide a nutrient rich setting for Burgess Shale
fauna as well as the setting in which to preserve them. The abundance of fossils around these pools may be due in part to chemo-symbiosis. Expeditions to the hot, mineral rich vents (black smokers) in the MidAtlantic Ridge have identified bivalves and other organisms in lifesustaining relationships with sulphide and methane oxidizing bacteria. This may be occurring at the foot of the Cathedral Escarpment and provides an indication of the importance of this these kinds of settings to the rise of early life. Another reason why fossils haven’t been found away from the Cathedral Escarpment is that the buttress of the escarpment provides protection from the regional deformation and metamorphism that generated a vertical (fossil destroying) cleavage away from the escarpment.
There is a complex mixture of processes depositing sediment at the foot of the escarpment, dominated by dense flowing mud-slurries but also including minor turbidites, subordinate sediment rain and rare catastrophic collapses of the escarpment providing coarse angular debris (Gabbot and Zalasiewicz, 2009). These processes led to quick burial of organisms in anoxic conditions within decimetre thick flows, away from both scavengers and the bacterially active sediment-ocean interface. Early models of Burgess Shale fossil preservation involved the fauna being swept over the edge of the escarpment from shallower waters of the adjacent platform, followed by rapid burial. But it now appears that many were living in the depths, proximal to the seeps and so haven’t been transported as far as previously thought.
Prior to uplift and erosion, Cambrian sediments were buried as much as 10 km deep and experienced low grade green schist stage metamorphism. Slate and schists evolve from metamorphosed shale when pressure and temperature cause the formation and reorientation of phyllosilicates (clay minerals) at angles oblique to the original bedding. One can see excellent examples of slate belonging to the Miette Group exposed along the Trans-Canada Highway, enroute to the hike, at the intersection of Hwy 1 and 93 (Icefields Parkway).
Soft bodied preservation occurs at numerous stratigraphic levels within the Burgess Shale, but the best known and most spectacular are at the original Walcott Quarry. The Burgess Shale is one of the World’s best known lagerstatten; a deposit showing prolific and exceptional preservation of otherwise rarely preserved flora and fauna. The diverse flora and fauna here includes annelid, priapulid, onychophoran and chaetognath worms, brachiopods, echinoderms, chordates (including our distant ancestor Pikaia), sponges, jellyfish, algae and cyanobacteria. As is the case today the most diverse fauna are the arthropods. Of these the most abundant is the feathery limbed arachnomorph (called a “lace-crab” by Walcott) Marrella splendens. Other arthropods include soft (Naraoia) and hard (Olenoides, Habelia, etc) shelled trilobites, Canadaspis ( a distant relative of shrimps and lobsters), the large predatory anomalocaridids (such as Hurdia and Anomalocaris), and bivalved forms such as Tuzoia and Odaraia. One of the more unusual arthropods is Opabinia; the five eyed wonder with a trunk-like grasping appendage.Your guides will show you some of these amazing fossils and provide you with a introduction to the geology and paleontology of the site. There are numerous publications which allow you to explore deeper; some of these are included in the references.
References:
• Balkwill, H.R., Price, R.A., Cook, D.G., and Mountjoy, E.W.,1980. GSC Map 1496A; Golden, East Half.
• Butterfield, N., 2009. Fossil Preservation in the Burgess Shale. In “A Burgess Shale Primer; History, Geology and Research Highlights”, ICCE 2009 Field Trip Companion Volume.
• Caron, J.B., 2006. Taphonomy of the Greater Phyllopod Bed Community, Burgess Shale. PALAIOS(2006),21(5):451
• Collom, C.J., Johnston, P.A., & Powell, W.G. (2009). Reinterpretation of ‘Middle’ Cambrian stratigraphy of the rifted western Laurentian margin: Burgess Shale Formation and contiguous units (Sauk II megasequence), Rocky Mountains, Canada. Palaeogeography, Palaeoclimatology, Palaeoecology, 277, 63-85.
• Conway-Morris, Simon, 2000. The Crucible of Creation: The Burgess Shale and the Rise of Animals, Oxford University Press.
• Coppold, M. & Powell, W., 2006. A Geoscience Guide to The Burgess Shale. The Burgess Shale Geoscience Foundation 2006, 76p.
• Fletcher, T.P., and Collins, Desmond, 2009. Geology and Stratigraphy of the Burgess Shale Formation on Mount Stephen and Fossil Ridge. In “A Burgess Shale Primer; History, Geology and Research Highlights”, ICCE 2009 Field Trip Companion Volume.
• Gabbot, S., and Zalasiewicz, J., 2009. Sedimentation of the Phyllopod Bed within the Cambrian Burgess Shale Formation. In “A Burgess Shale Primer; History, Geology and Research Highlights”, ICCE 2009 Field Trip Companion Volume.
• Gould, S.J., 1989. Wonderful Life; The Burgess Shale and the Nature of History.. 347 pp. New York: W. W. Norton & Company
• Johnston, P.A., Johnston, K.J., Collom, C.J., & Powell, W.P. (2009). Palaeontology and depositional environments of ancient brine seeps in the Middle Cambrian Burgess Shale at The Monarch, British Columbia, Canada. Palaeogeography, Palaeoclimatology, Palaeoecology, 277, 86-105.
• Powell, W.G., Johnston, P.A, Collom, C.J., and Johnston, K.J., 2006, Middle Cambrian brine seeps on the Kicking Horse Rim and their relationship to talc and magnesite mineralization, and associated dolomitization, British Columbia, Canada. Economic Geology, v.101, p. 431-451.
• Powell, W.G., 2003, Greenschist-facies metamorphism of the Burgess Shale and its implications for models of fossil formation and preservation. Canadian Journal of Earth Sciences, v.40, p. 13-25
• Price, R.A., Cook, D.G., Aitken, J.D., and Mountjoy, E.W.,1980. GSC Map 1483A; Lake Louise West Half.
• Shin, E.A., 1968. Practical Significance of Birdseye Structures in Carbonate Rocks. Journal of Sedimentary Petrology, Vol . 38, No.1, pp 215-223. March 1968.
• Stewart, W.D., Dixon, O.A., Rust, B.R., 1993. Middle Cambrian carbonate-platform collapse, southeastern Canadian Rocky Mountains. Geology 21, 687–690.
• Whittington, H.B.; Briggs, D.E.G. (1985). The largest Cambrian animal, Anomalocaris, Burgess Shale, British Columbia. Philosophical Transactions of the Royal Society of London B. 309 (1141): 569–609.
Monday, May 4, 2015
6:00 pm – 7:30 pm
Hyatt Regency Calgary, Imperial Ballroom
Everyone is invited to attend
Please register (no charge) at www.cspg.org under EVENTS tab See award recipients and citations on the website under MEMBERS tab
Phil Esslinger has been an active member of the CSPG since 1989. He started his career with Petrel Robertson in 1988 and joined Rakhit Petroleum Consulting Ltd in 1990 where he worked on hydrogeology, geochemistry and regional exploration studies. He has held a series of exploration/development roles with Encana/Cenovus since 2004 and currently is a Sr. Staff Geologist leading the Grand Rapids Subsurface team for Cenovus. Phil served on the organizing committee for the CSPG Hydrogeology Division from 1995 until 2004 and acted as chairman from 1997 to 2000. He has been awarded two CSPG Service Awards - for his efforts with the Hydrogeology Division (2001) and for his role as one of three organizing co-chairs of the inaugural Gussow Mini-Conference (2003). The Gussow conference has since become a very successful part of the CSPG’s technical conferences. Phil has presented numerous times at the CSPG Annual Convention and published in the CSPG Bulletin. He served as the CSPG General Co-Chair for the 2014 GeoConvention for which he is being awarded the 2014 CSPG Tracks Award.
Dawn Hodgins discovered her geology career/adventure at the University of Manitoba when she wondered into a “rocks for jocks” geology class. She was hooked and one year later she moved to Calgary,
changing her career path, city and university. She completed her B.Sc. (Geology) and her M.Sc. (Structural Geology) at the University of Calgary all while working part time for various-sized oil and gas companies. While completing her M.Sc., Dawn started her career with ExxonMobil Canada/Imperial Oil. For 12 years she worked various assets, both conventional and Heavy Oil, in Western Canada and the Arctic. Currently she is located in St John’s Newfoundland working on Hibernia field. In 1997 Dawn was the U of C candidate for the Student Industry Field Trip (SIFT) and has been an active member of the CSPG family ever since. Dawn was a senior member of the SIFT committee for 15 years (two years as chair of the committee). An opportunity presented itself to represent students and hard working committee members at the next level up in the CSPG organization. In 2012 Dawn join the ranks of the CSPG Board as the Outreach Director followed by a brief term with Education Trust Fund. Promoting and progressing petroleum geoscience with future generation geoscientists has always been a passion for Dawn and she hopes to continue those endeavors in East Canada.
Geoff Speers was introduced to the CSPG while attending its flagship student outreach program, the Student Industry Field Trip (SIFT), in 2005 as the Brandon University representative. After graduating the following year Geoff moved to Calgary to continue his career with Pengrowth Energy, the company he still works with today. In his duration with Pengrowth, Geoff has nearly worked through the company’s entire portfolio of assets, with current focus on exploration and development of the Unconventional Resources within the Cardium, Mannville, Elkton and Montney formations.
Geoff currently holds the volunteer position of SIFT Exploration Game coordinator,
a major component of the overall SIFT experience. Students are placed within a mock exploration scenario where they must apply geologic interpretation and mapping skills to successfully purchase lands, and drill wells, simulating real life oil and gas company day-to-day operations.
The SIFT organizing committee has long recognized a need to revamp the Exploration Game portion of the program, which had not been updated since inception some 30+ years prior. In 2014 Geoff undertook the task of creating and implementing a new and improved exploration game which focused students’ attention on geologic mapping of a real life development area within the WCSB.
Geoff would like to take this opportunity to thank all past and present CSPG SIFT volunteers, in particular past chair Taylor Olson, for nominating him for this prestigious award. Without the tireless dedication of these volunteers the CSPG SIFT program would not be possible.
Eric Street has been a member of the CSPG since his university days at Simon Fraser University where he received a B.Sc. in Earth Sciences. He was introduced to the petroleum industry through the CSPG’s Student Industry Field Trip (SIFT) and summer internships at Encana Corporation. Eric began his professional career at Encana working on the Cretaceous sedimentary succession of the Western Canadian Sedimentary Basin. Seeking international experience on conventional plays, he became an integral member of the team that successfully explored for and developed the “N Sand” play in the Putumayo Basin of Colombia with Suroco Energy and Petroamerica. Eric is currently developing Deep Basin assets with Jupiter Resources. His most significant CSPG volunteering efforts came in 2014 when he served as a technical co-chair of the GeoConvention.
Enviro-Tech
Sproule
Target
Petrocraft
RIGSAT
Cabra Enterprises Ltd.
Cougar Consultants, Inc.
SAExploration
NExT-
Petrel
Roke
Mcleay
HEF
Inc.
Korean National Oil Company
Long Reach Resources Ltd.
Lorne LeClerc & Associates
Madison Petrogas Ltd.
Petroamerica
Serinus Energy
Sherritt International Corporation
Skyhawk Exploration
Tretio Exploration Ltd.
Valeura Energy
Company Patron
Journey Energy Inc.
Rife Resources Ltd.
In 2014 a total of 20 theses were submitted - nine M.Sc. and an unprecedented eleven Ph.D. theses - representing nine universities across Canada. The recipients of the awards are as follows:
Best Ph.D. - Dallin Laycock for his thesis entitled “Stratigraphy, Sedimentology and Geochemistry of Mudstone Dominated Clinoforms and their Depositional Environments, Carlile Formation, Eastern Alberta, Canada” (supervised by Prof. Per Kent Pedersen and Prof. Ron Spencer at the University of Calgary).
Honorable Mention Ph.D. – Benjamin Cowie for his thesis entitled “Stable Isotope and Geochemical Investigations into the Hydrogeology and Biogeochemistry of Oil Sands Reservoir Systems in Northeastern Alberta, Canada” (supervised by Prof. Bernhard Mayer at the University of Calgary).
Best M.Sc. – Rares Bistran for his thesis entitled ”Sedimentology and Neoichnology of a Mixed-Energy Estuary, Tillamook Bay, Oregon, United States” (supervised by Prof. Murray Gingras and Prof. J-P Zonneveld at the University of Alberta).
–
Zambrano for her thesis entitled “Reservoir Characterization of the uppermost Monteith Formation -Tight Gas Sandstones in the Western Canada Sedimentary Basin in Alberta, Canada” (supervised by Prof. Roberto Aguilera and Prof. Per Kent Pedersen at the University of Calgary).
The full citation of award winners can be seen in the March issue of the Bulletin of Canadian Petroleum Geology or on the CSPG website under Members>Student Awards.
